Canada's Oil Sands: Shrinking Window of Opportunity

Canada’s Oil Sands Shrinking Window of Opportunity

May 2010

Ceres99 Chauncy StreetBoston, MA 02111

T: 617-247-0700F: 617-267-5400

www.ceres.org

©2010 Ceres

A Ceres Report

Authored by RiskMetrics GroupYulia Reuter

Doug Cogan

Dana Sasarean

Mario LÓpez Alcalá

Dinah Koehler

REPORT AUTHORS

YULIA REUTERYulia Reuter heads the global oil and gas team for ESG Analytics of RiskMetrics Group. She

joined Innovest Strategic Value Advisors in 2007 to conduct research on the integrated

oil & gas sector. Previously, Ms. Reuter worked for fi ve years conducting oil & gas equity

research and institutional equity sales in the Canadian investment banking sector. She is a

Chartered Financial Analyst and holds a Bachelor’s Degree in Business Administration from

the Groningen University of Applied Sciences (Netherlands). Ms. Reuter is based in Toronto.

DOUG COGANDoug Cogan is Director of Climate Risk Management at RiskMetrics Group. For 25 years, Mr.

Cogan has advised institutional investors, corporations and government agencies on energy

and environmental topics. His 1992 book, Th e Greenhouse Gambit, was one of the fi rst to

analyze business and investment responses to climate change. He has written many reports

for Ceres and the Investor Network on Climate Risk and helped develop the INCR-adopted

Climate Change Governance Framework. He heads a team using the proprietary Carbon Beta

tool to evaluate companies’ carbon risks and strategic profi t opportunities. He is a graduate of

Williams College.

DANA SASAREANDana Sasarean is a senior analyst with the global oil and gas team for ESG Analytics of

RiskMetrics Group. She joined Innovest Strategic Value Advisors in 2005 to conduct research

on extractive industries, including the integrated oil & gas sector. Ms. Sasarean now focuses

on downstream and oil services sectors. She earned a Master’s Degree in Environmental

Studies from York University (Canada) with concentration in the management tools for

sustainability, ISO 14001 and environmental auditing. She also holds a Bachelor’s Degree in

Finance and Banking from the West University of Timisoara (Romania).

MARIO LÓPEZ-ALCALÁMario López-Alcalá is a senior analyst with the Climate Risk Management team at RiskMetrics

Group. He works in the development and structure of research models and analytics for

climate change-exposed industries. Previously, López-Alcalá conducted research on climate

change for the United Nations Development Programme, Th e World Bank, and the European

Commission. López-Alcalá holds a Masters on Environmental Science and Policy from

Columbia University. He has a Bachelors degree in Economics from Instituto Tecnólogico

Autónomo de México, and holds a Law degree from Universidad Nacional Autónoma de

México.

DINAH KOEHLERMs. Koehler is an ESG consultant. She has 17 years of experience in the public and private

sectors and academia. She has worked with the U.S. Environmental Protection Agency’s Offi ce

of Research and Development, National Center for Environmental Research. She has been a

Senior Research Associate on corporate sustainability at the Conference Board, and continues

to serve there in a consulting role. Ms. Koehler earned her doctorate in Environmental Science

and Risk Management from Harvard’s School of Public Health, received an M.A., Law &

Diplomacy from Th e Fletcher School at Tufts University, and a BA from Wellesley College.

Th is report was written by members of the ESG Analytics team at RiskMetrics Group. Yulia

Reuter served as research project manager. Doug Cogan edited the report and wrote its

summary and conclusions. Ms. Reuter and Dana Sasarean conducted macroeconomic

research and drafted the water, land and Aboriginal rights chapters. Mario López-Alcalá and

consultant Dinah Koehler conducted carbon modeling research and drafted the oil sands

production chapter. Th e report authors wish to thank Andrew Logan, Carol Lee Rawn, Peyton

Fleming and Andrew Gaynor of Ceres who along with Ceres consultant Sonia Hamel provided

valuable insights and editing suggestions. Maggie Powell of Maggie Powell Designs produced

this report for publication. Peter Essick, Aurora Photos, provided the cover photograph.

Ceres is a national coalition of investors, environmental groups and other public interest

organizations working with companies to address sustainability challenges such as global

climate change. Ceres directs the Investor Network on Climate Risk, a group of more than 90

investors from the US and Europe managing nearly $10 trillion in assets. Th is report was made

possible through grants from the Energy Foundation, Tides Foundation, Wallace Global Fund,

Oak Foundation and Kresge Foundation. Th e opinions expressed in this report are those of

the authors and do not necessarily represent the views of the sponsors.

RiskMetrics Group (RMG) is a leading provider of risk management and corporate governance

products and services to the fi nancial community. By bringing transparency, expertise and

access to fi nancial markets, RMG’s ESG Analytics Group off ers investors insight into the

fi nancial impact of sustainability risk factors such as climate change, environmental

protection and human and stakeholder capital.

For more information, please contact:

Andrew Logan

Director, Oil & Gas Industry Program

Ceres, Inc.

+1.617.247.0700 ext. 133

[email protected]

RiskMetrics Group wrote and prepared this report for informational purposes.

Although RiskMetrics exercised due care in compiling the information contained herein,

it makes no warranty, express or implied, as to the accuracy, completeness or usefulness of

the information, nor does it assume, and expressly disclaims, any liability arising out of the use

of this information by any party. Th e views expressed in this report are those of the authors

and do not constitute an endorsement by RiskMetrics Group. Changing circumstances may

cause this information to be obsolete.

Copyright 2010 by Ceres

Copyrighted RiskMetrics Group material used with permission by Ceres

Ceres, Inc.

99 Chauncy Street

Boston, MA 02111

www.ceres.org

RiskMetrics Group Inc.

One Chase Manhattan Plaza

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New York, NY 10015

www.riskmetrics.com

Doug Cogan

Director, Climate Risk Management


+1.301.793.6528

[email protected]

Yulia Reuter

Head of Oil & Gas Research, ESG Analytics


+1.416.364.9000, x3484

[email protected]

1Canada’s Oil Sands: Shrinking Window of Opportunity

Table of ContentsForeword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Historical Perspective on Oil Sands Development . . . . . . . . . . . . . . . . . . . . . . . . . 12

List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Oil Sands Production Primer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1. Macroeconomics of Oil Sand Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1.1 Price of oil and oil sands production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18

1.2 Price of natural gas and oil sands production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20

1.3 Canadian sands and the U.S. petroleum market . . . . . . . . . . . . . . . . . . . . . . . . . . .21

1.4 Oil demand constraints in the United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25

1.5 Low carbon fuel standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31

1.6 Sensitivity analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .41

1.7 Modeling conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .46

2. Water and Oil Sands Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

2.1 Water primer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .49

2.2 Catalysts for sustainable water management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .50

2.3 Water use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51

2.4 Water availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .53

2.5 Conclusions on water management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56

3. Land and Oil Sands Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

3.1 Overview of land risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58

3.2 Tailings primer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59

3.3 Tailings production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .60

3.4 Footprint on land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63

3.5 Health consequences of water and soil contamination . . . . . . . . . . . . . . . . . . . . .64

3.6 Contingent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65

3.7 Regulatory catalysts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .66

3.8 Tailings management options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .67

3.9 Increased salt budgets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .69

3.10 Tailings remediation costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .70

4. Aboriginal Rights and Oil Sands Development . . . . . . . . . . . . . . . . . . . . . . . . 75

4.1 Historical background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .75

4.2 Interpretation of indigenous rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .75

4.3 Legal cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .76

4.4 Failed stakeholder consultation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .77

4.5 Summary of legal risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .78

5. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

5.1 Finding the right growth trajectory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .79

5.2 Shrinking window of opportunity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .80

5.3 Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .81

5.4 Carbon emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .82

5.5 Low carbon fuel standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83

5.6 Water use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .85

5.7 Land reclamation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .87

5.8 Aboriginal consultation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .89

5.9 Towards a strategic plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .90

2 Canada’s Oil Sands: Shrinking Window of Opportunity

ForewordOil, the lifeblood of transportation, is a key driver of the global economy. As the

world comes out of recession, oil demand is resuming its inexorable rise, with the U.S.

alone consuming 23 percent of global supplies in 2008. While just over half of U.S.

oil comes from overseas countries like Venezuela, Saudi Arabia and Iraq, the fastest

growing source is from North America — in particular, from the Gulf of Mexico and

Canada’s vast oil sands regions. Oil production from these two areas has grown to 3

million barrels a day in recent years, supplying more than 15 percent of total U.S. oil

needs.

Yet, while this growing reliance on locally produced oil has some economic and

perceived national security benefi ts, it also comes loaded with signifi cant costs.

While all oil extraction has environmental impacts, oil production from challenging

frontier areas like the deepwater Gulf of Mexico and Canada’s oil sands carries higher-

than-average risks. Th e BP oil spill in the Gulf of Mexico has made these risks acutely

tangible for investors, with BP’s shareholder value taking a $30 billion hit amid a wave

of lawsuits by fi shermen and other local industry groups.

Th e risks for companies involved in developing Canada’s oil sands — the largest energy

project in the world, and the focus of this report — are arguably greater than those in

the Gulf of Mexico. Most of these risks are related to the energy- and water-intensive

nature of oil sands production, risks that will only increase as the industry seeks to

double or even triple production in a world that is increasingly becoming water- and

carbon-constrained. Oil sands production requires extracting synthetic crude oil from

the highly viscous bitumen buried across vast stretches of Alberta, Canada.

One of the key risks facing investors is the narrow profi t window for oil sands

production. Th e oil sands are the world’s most expensive source of new oil, and

new production requires prices of at least $65 per barrel, and potentially as high

as $95 per barrel, to make economic sense. Increasing environmental regulations,

including emerging carbon limits, will cause this fl oor price to rise. Adding to the

project’s risk profi le are resource constraints that could limit future production —

specifi cally, adequate water and natural gas supplies that are linchpins for boosting

oil production.

Finding a marketplace for ever-increasing oil sands production is another major

question. Presently, the vast majority of the 1.3 million barrels being produced every

day fl ows to the United States. Th is market is jeopardized, however, by emerging

low-carbon fuel standards in the U.S. that will require a lower carbon intensity in

transportation fuels. In order to have access to these markets, oil sands output

will likely have to be mixed with next-generation biofuels which are not yet being

produced on a commercial scale. Th ese fuel standards, already adopted in California,

will put carbon-intensive oil sands fuel at a distinct disadvantage.

Another alternative is transporting these oils west to China and other Asian markets.

However, there is strong opposition to building pipelines to Canada’s West Coast

from Aboriginal communities who have signifi cant rights under the Canadian

Constitution.


Added together, these wide-ranging challenges will make oil sands production

increasingly risky in the years ahead. Among the report’s conclusions is that global oil

prices will need to remain high — possibly approaching $100 a barrel — to justify the

planned $120 billion expansion in the oil sands region in the next decade. Oil sands

producers must also be mindful that if global oil prices get too high, above $120-$150

a barrel, it will likely reduce global oil demand and shift markets in favor of alternative

fuels. Bottom line: oil sand producers are operating in a narrowing window of

profi tability.

Investors are right to be pushing oil companies to provide detailed explanations on

how they are responding to these wide-ranging challenges. Shareholder resolutions

requesting such disclosure were fi led with many leading oil sands producers this year,

including BP, Shell, ExxonMobil and ConocoPhillips.

Th ese resolutions — and the report’s fi ndings — are a wake up call for oil companies

to move quickly to examine and respond to these multiple challenges. Companies

such as Suncor have shown a willingness to tackle these issues, both by improving

their disclosure and attempting to address tough environmental challenges such as

remediating the vast land areas now covered by polluted tailings ponds.

All oil sands companies should be tackling these challenges and we hope this report

will expedite such action. Likewise, investors should be pressing companies to analyze

and mitigate their potential risk exposure from this unconventional oil extraction

project that has already attracted fi nancial commitments of $200 billion, with

potentially much more to come.

Mindy S. LubberPresident, CeresDirector, Investor Network on Climate Risk


Executive SummaryCanada’s vast oil sands are the focus of the world’s largest energy project. Th e

Province of Alberta is home to the world’s second largest hydrocarbon basin, after

Saudi Arabia, containing approximately 175 billion barrels of proved reserves.

Virtually every major Canadian and international oil company, including Suncor,

ExxonMobil, Shell and ConocoPhillips, has a fi nancial stake in this resource, with

$200 billion committed to current and future oil extraction projects covering an area

the size of Greece. Th ese companies are betting that demand for higher-priced oil is

here to stay. As oil prices climb above $80 per barrel, producers are optimistic that

they can double oil sands production over the coming decade, and more than triple

output by 2030 to produce more than 4 million barrels per day. Th at is more than

double current oil production in the Gulf of Mexico.

However, oil sands production is expensive and faces signifi cant risks associated with

its environmental and social impacts. Th is report concludes that if the industry does

not take steps to aggressively manage these risks, its long-term growth is in doubt.

Production of crude oil from highly viscous bitumen requires substantial amounts

of energy and water; hence, oil sands production in Alberta comes at a high fi nancial

price. In addition, the process exacts a heavy environmental toll. Bitumen mining

mars the landscape and consumes large volumes of water that end up in toxic

tailings ponds. In-situ production fragments wildlife habitat and is extremely carbon-

intensive. Restoring this vital ecosystem will require sustained investments in land

reclamation and water treatment projects, which presents one of this industry’s

biggest long-term challenges.

At the same time, oil sands development is turning an expanding section of Canada’s

vast boreal forest, one of the world’s largest carbon sinks, into one of the fastest-

growing manmade sources of carbon dioxide emissions. With continued expansion,

oil sands operations are forecast to rise from 5% to 15% of Canada’s total CO2

emissions by 2020, working against national and global goals to achieve substantial

GHG emission reductions. A CAD $15 per ton levy imposed on CO2 emissions in

Alberta in 2007 has had little demonstrable eff ect in altering companies’ production

plans. However, the eff ects of climate regulations, including emerging Low Carbon

Fuel Standards (LCFS), in the U.S. and Canada will likely apply added pressure on the

industry to reduce its growing carbon footprint.

Th is report examines how carbon and land reclamation regulations, climate change

and other environmental and social issues may adversely aff ect the future of oil

sands development in Alberta. Multiple risks are addressed in detail. Although

Alberta is considered a safe haven for oil producers relative to other more politically

volatile regions of the world, Canada’s own Aboriginal communities pose a potential

roadblock to oil sands’ expansion, and some have already called for a moratorium

on new projects and pipelines that would open new key trade routes for distributing

oil. Canada’s dominant oil export market, the United States, is also undergoing a

wholesale review of its energy policy. With a renewed focus on promoting energy

effi ciency and low-carbon technologies, the United States could substantially reduce

demand for this carbon-intensive fuel.


As outlined in the chapters that follow, this report concludes that the rush to develop oil sands brings many risks for companies and investors. Rising

production costs and asset retirement obligations could erode the balance sheets

of these companies. Carbon costs and mounting environmental regulations could

detract from their bottom lines. Companies must be willing to invest upfront to

address these challenges when designing new projects, while recognizing that cost-

eff ective solutions in many instances do not yet exist. Th is quandary leaves oil sands

producers exposed to growing risks and a shrinking window of opportunity that may

close over time.

Key Report FindingsCanada’s oil sands companies operate in a shrinking window of opportunity. Th ese producers of unconventional crude oil face volatile global energy markets

and rising production costs. Th ey need global oil prices to stay above at least $65

per barrel—and possibly above $95 per barrel—to justify $120 billion in planned

expansion projects over the next decade. Th e production fl oor price for oil sands is

rising with the onset of carbon pricing, higher input commodity prices and growing

regulatory expenditures for water treatment and land reclamation. At the same time,

global oil prices may rise to the point where they quash petroleum demand and

permanently shift markets in favor of alternative fuels. Th is upper price limit may

be in a range of $120–$150 per barrel. Such a relatively low ceiling combined with

the rising fl oor price creates a narrow window for future oil sands development that

could shrink and possibly close altogether if the industry is unable to manage these

risks and signifi cantly reduce the costs of production.

Some Aboriginal communities and investors in Canada support a moratorium on new oil sands projects and pipelines. Th e collapse in oil prices in 2008 brought

about a de-facto moratorium on new oil sands projects. While that freeze appears

to be lifting, Aboriginal communities with rights granted under the Canadian

constitution still could block signifi cant expansion. If oil sands production is limited

to current operating projects in addition to those under construction, estimated

total production volume would rise from 1.2 million barrels/day (mbbl/d) in 2008 to

2.0 mbbl/d by 2015. Oil sands producers have their sights set on much higher output,

however. With rising oil prices, they believe oil sands volume could double by 2020,

triple by 2030 and reach still higher volumes if oil prices are sustained at levels well

above today’s prices.

Th e United States is likely to remain the dominant market for Canadian oil sands producers for the foreseeable future. Canada has been the United States’

largest foreign oil supplier since 2004, surpassing Saudi Arabia; more than two-

thirds of Canadian oil production was exported to the U.S. market in 2008. Canada’s

portion of U.S. oil imports is projected to remain at about 22% through 2035, with oil

sands’ contribution rising from 59% to more than 80% of the total Canadian supply

after 2020. Eff orts to build oil sands pipelines to Canada’s west coast for exports to

Asia so far have been slowed by Aboriginal and community opposition. Th is leaves

Canadian oil sands producers highly dependent on the U.S. market and the future

course of its energy policy.


Newly introduced LCFS rules in the U.S. and Canada are intended to reduce the carbon intensity of transportation fuels, putting oil sands producers at a disadvantage. Th e LCFS rules require a gradual decrease in the full life cycle carbon

emissions of these fuels, which poses a particular challenge for oil sands because

of their high carbon intensity and low energy return on energy invested (EROEI). It

takes three times more units of energy to extract bitumen from oil sands than oil

from conventional wells. Only seven units of energy are returned for each unit of

energy invested to extract bitumen from oil sands (resulting in an EROEI ratio of 7:1),

whereas pumping oil from conventional wells yields a 22:1 ratio. After upgrading

and refi ning, the EROEI of oil sands falls to just 3:1. Th is puts oil sands at a distinct

disadvantage to conventional petroleum on a carbon-intensity basis. Measuring

emissions from the time of extraction through end use as motor fuels—a “fi eld-to-

wheels” analysis—oil sands derived fuels are 12% more carbon-intensive on average

than those derived from conventional oil. California adopted an LCFS standard in

2009, and similar regulations are under consideration in more than half of the U.S.

states and four Canadian provinces. If one quarter of the U.S. motor vehicle market

were subject to an LCFS standard requiring a 10% reduction in the average carbon

intensity of gasoline by 2020 (equal to a 20% reduction for synthetic crude oil), with

a further 10% reduction required by 2030, the resulting demand reduction could

curtail oil sands production volume by 13.5% compared to our estimated baseline

forecast of 3.7 mbbl/d in 2030. If an LCFS standard was adopted by all 50 U.S. states,

Canadian oil sands production could be further curtailed, to 2.5 mbbl/d in 2030, a

33% decline relative to our baseline forecast.

Growing availability of renewable transportation fuels would support oil sands producers’ compliance with LCFS. To off set the higher carbon intensity of oil

sands, low-carbon renewable fuels can be blended with this synthetic crude to meet

the reduced carbon-intensity targets under an LCFS. Advanced renewable fuels like

cellulosic ethanol are the preferred blending option because they have less than half

the carbon intensity of conventional petroleum and lower carbon intensity than

widely available corn-based ethanol. However, advanced renewable fuels are not

yet produced in large commercial quantities. Th is gives oil sands producers a strong

incentive to support the growth of this industry. In the unlikely event that no options

emerge to enable Canadian oil sands producers to comply with a federal LCFS in the

United States, demand could fall below the 2.0 mbbl/d production volume that oil

sands producers already have in operation and under construction.

Other carbon off set options for oil sands producers may be costly and diffi cult to obtain. Carbon capture and sequestration (CCS) is a critical technology that could

help reduce the carbon-intensity of oil sands production relative to conventional

crude oil. However, only the upgrading and hydrogen processing elements of the oil

sands production process yield high-CO2 waste streams that lend themselves to ready

capture. Moreover, pipelines would have to be built (extending up to 1,000 miles)

to transport this captured CO2 to geographically suitable regions, and assurances

would be needed that this CO2 would remain safely sequestered in underground

reservoirs for many centuries. Projected initial costs of CCS for oil sands range from

CAD $70-150 per ton of CO2 sequestered. Other types of carbon off set credits may

be available within the transportation sector. However, these off sets, too, are likely

to be expensive and may not be available in the quantities that oil sands producers

would require. Because conventional oil producers would need proportionately fewer

credits to meet LCFS rules, they will be the likely drivers of this market. Th is may


leave oil sands producers with only the most expensive LCFS purchase options—or

possibly none at all. We estimate that LCFS credits selling for $100/ton would have

the eff ect of raising the price of oil sands production by $11.40 per barrel to achieve a

10% carbon-intensity reduction target (equal to a 20% reduction for synthetic crude).

Water shortages could emerge as an oil sands production constraint by 2014. Oil

sands production is highly water-intensive, with up to four barrels of water consumed

for every barrel of oil produced from surface mining projects. (Th e ratio is less than

1:1 for underground, in-situ projects.) Water withdrawals from the Athabasca River

watershed are already restricted during winter months to protect fi sh habitat. If oil

sands production volume grows according to companies’ estimates, some oil sands

mining operations could exceed their wintertime allowances by as early as 2014,

causing possible production interruptions. Along with new provincial water control

regulations, this is likely to prompt oil sands producers to make signifi cant additional

investments in water storage, treatment and recycling facilities. Climate change may

exacerbate this water management challenge. Glaciers that feed into this watershed

are already shrinking, and some scientifi c studies forecast that the Athabasca River’s

water fl ow could shrink by 50% in winter months by mid-century. Th is places oil

sands producers in possible competition with other agricultural, municipal and

industrial water consumers in Alberta.

Land reclamation presents growing operating costs and liability for some oil sands producers. After 40 years of production, no oil sands company has

fully reclaimed tailings ponds created by development. Th at is because the fi ne

particulates in toxic mining waste take decades to settle out in tailings ponds. Such

tailing ponds—already covering an area the size of Washington, D.C.—pose risks

of contaminating adjoining soil and water resources, and present health problems

in downstream communities as well as the risk of a catastrophic breach. Alberta’s

Directive 74 requires oil sands miners to speed up the remediation process of existing

ponds and progressively treat tailings. Th is may pose a particular challenge to some

of the oil sands industry’s biggest legacy miners. For example, if bioremediation is

used to expedite this treatment process, our analysis fi nds that Canadian Oil Sands

Trust (COST) could see a 10-26% increase in its debt-to-capitalization ratio to cover

its added asset retirement obligations.

Opposition by First Nations and other Aboriginal communities poses a growing material risk to oil sands producers. Some Aboriginal leaders have passed joint

resolutions calling for a moratorium on new oil sands project approvals until

appropriate engagement and consultation with their local governments takes

place. Canada’s Constitution recognizes the rights of these Aboriginal communities

to protect their traditional livelihoods, including a right to be consulted about

development activities and to have their hunting and fi shing rights accommodated.

To date, neither the Albertan nor Canadian governments, nor any oil sands

producers, have engaged with Aboriginal communities on the basis of Free, Prior

and Informed Consent, which is their preferred means of engagement. Th is raises the

specter of protracted legal battles and — in the worst case — possible annulment of

oil sands leases that could compromise the industry’s future expansion plans.


Recommendations for Future Oil Sands DevelopmentInvestment in the oil sands has grown in large part because the industry has few

other options for developing signifi cant new reserves. Some industry analysts have

concluded that more than half of the oil that is open to investment by western

companies is now located in Canada’s oil sands. As global oil demand continues to

grow, so too will pressure to expand this resource. What this report underscores is

that oil sands investment is not without signifi cant risks. Companies should proceed

with caution and make clear plans for managing risks associated with carbon

emissions, water scarcity and land reclamation.

Oil sands producers should review the lasting impacts of their proposed development plans and pursue more pro-active, incremental strategies. Community opposition and investor concerns about oil sands development

will persist until oil sands companies do a better job of articulating their plans

for ongoing community and stakeholder engagement, land use planning, water

management and carbon mitigation. Oil sands producers would do well to view this

as an opportunity to examine how their fi nancial prospects will be aff ected by rising

production costs, increased liabilities and changing global energy policies that narrow

the window on future oil sands development. Oil sands companies should also be

disclosing information from these more detailed evaluations to investors.

If the aforementioned energy and water issues could be remedied, stronger ties between Canadian oil sands producers and the U.S. biofuel industry could lead to a greener North American economy. Th e spread of LCFS standards from

California to other regions of the United States and Canada could foster a closer

working relationship on both sides of the border. Existing Canadian oil sands

pipelines feed mainly into the U.S. Midwest, which has substantial infrastructure in

place to process this fuel and combine it with signifi cant biofuel production capacity.

Building on this relationship with new investments in advanced renewable fuels

would help oil sands derived fuel achieve LCFS standards, spur more employment in

clean technology industries and promote regional energy independence that could

enable North America to compete more eff ectively against Europe and Asia as they

advance their own low-carbon economies.

A more comprehensive and better articulated long-term strategy will give investors a clearer picture about the scale and pace at which appropriate development should take place. At the same time, companies will gain more

confi dence in their own strategic planning decisions and be more likely to gain

backing from wary stakeholders, investors and policymakers. Th e alternative leaves

these vital questions unanswered and only raises the stakes in the multi-billion dollar

gamble that has become oil sands development in Alberta.


Disclosure Issues in Oil Sands Development

Energy and Carbon Management Oil, natural gas and carbon pricing forecasts in relation to future oil sands

production guidance

Assumed growth and participation in carbon trading schemes and markets

with Low Carbon Fuel Standards (LCFS)

Investments in R&D and technologies to reduce carbon emissions, including

renewable transportation fuels, carbon capture and sequestration (CCS) and

related infrastructure

Strategies and targets to reduce the CO2 intensity and overall greenhouse gas

emissions from operations and products

Water Use and Land Reclamation Water withdrawals and recycling rates from both surface and underground

sources

Freshwater/saline water recycling requirements for specifi c mining and in-situ

projects

Treatment of mining waste in tailing ponds and underground re-injection

Strategies and targets to increase water storage and freshwater/saline water

recycling

Climate change considerations in future water management plans

Human health and biodiversity impacts from cumulative oil sands

development activities

Plans to address new water use and land reclamation regulations (such as

Directive 74)

Eff ects of water treatment and land reclamation programs on operating costs

and asset retirement obligations

Aboriginal Consultation Disclosure of any risks posed by current Aboriginal rights litigation

Contact with Aboriginal communities and nature of any agreements in place

Participation in multilateral initiatives, such as the All Parties Core Agreement

Policies to guide future engagement, such as Free, Prior and Informed Consent

Company resources made available for these activities and for educating

employees about Aboriginal issues


List of Acronyms Used in this Report

ACES: American Competiveness and Energy Security Act (2009)

AEO: Annual Energy Outlook

AOSP: Athabasca Oil Sands Partnership

ARO: asset retirement obligation

ARRA: American Recovery and Reinvestment Act (2009)

Boe: barrels of oil equivalent

Bbls: barrels of oil

Bbls/d: barrels of oil per day

CAD: Canadian dollar

CAPP: Canadian Association of Petroleum Producers

CERA: Cambridge Energy Research Associates

CCS: carbon capture and sequestration

CO2: carbon dioxide

CO2e: carbon dioxide equivalent

CT: consolidated tailings

EIA: Energy Information Administration (U.S.)

ERCB: Energy Resources Conservation Board (Alberta)

EISA: Energy Independence and Security Act (2007)

EROEI: energy return on energy invested

FPIC: free, prior and informed consent

FT: fi ne tailings

GHG: greenhouse gases

LCFS: low carbon fuel standard

Mbbl/d: million barrels of oil per day

Mcf: thousand cubic feet of natural gas

MFT: mature fi ne tailings

RFS: renewable fuel standard

SAGD: steam assisted gravity drainage

SCO: synthetic crude oil

SOR: steam-oil ratio

THAI: toe-to-heel air injection


Historical Perspective on Oil Sands DevelopmentTh e fi rst documented accounts of Canadian oil sands came well before the arrival

of the Europeans, when the Cree and Dene native communities waterproofed

canoes with the boiled tar substance. As Canada’s great explorer of Scottish heritage

Alexander Mackenzie journeyed from Canada’s Atlantic East to the West Coast

in 1778 in search of the Northwest Passage, he noted the “bituminous fountains”

on the banks of the Athabasca River, which forms part of what is now known as

the Mackenzie River system – the world’s third largest watershed fl owing into the

Arctic Ocean. By the end of the 19th century, Ottawa became aware of the potential

benefi t of the oil sands resource, and signed a number of treaties with the Aboriginal

communities to protect the land and secure the resource for the Crown Domain of

the Dominion.

Th at this region is stored with a

substance of great economic value

is beyond all doubt, and, when the

hour of development comes, it will,

I believe, prove to be one of the

wonders of Northern Canada.

— Charles Mari in ‘Th rough the Mackenzie Basin’, Year 1899

Source: various, assembled by RMG


Th e modern history of “Canada’s Great Reserve” is relatively short. It was not until the

1920s that Dr. Karl Clark, an Alberta chemist, fi led a patent for the thermal extraction

technology that is still used today. He managed to separate bitumen from oil sands

through a hot-water process using his wife’s washing machine. Th e fi rst commercial

application was undertaken by J. Howard Pew, the U.S. industrialist and president of

Sun Oil Company in 1965, when the fi rst mine and upgrader (now known as Suncor)

was built on the Athabasca River. Shortly after, in 1973, Syncrude – now a consortium

of seven oil companies – followed suit. Following the oil crisis that year, the U.S.

government unsuccessfully lobbied Canada to secure energy supplies on the North

American continent by accelerating development through a $20 billion investment

program, funded by an international consortium and an $8 billion U.S. government

industrial assistance program. Th e second attempt to spur investment came in the

early 1990s, when the National Oil Sands Task Force, a public private-partnership,

was formed to attract $25 billion in investment under the so-called Declaration of

Opportunity.1

Investments fl owed into the area in the beginning of the 21st century, when oil prices

began a steady climb. Th e third mine, the Albian Sands project operated by Shell, was

brought into production in 2003. During 1997–2006, CAD $59 billion was invested

into the sector, and CAD $80 billion in additional investment was planned for 2007–

2010.2 Following the oil price collapse in 2008, investment timelines were pushed

back, and a majority of new projects were put on hold. Nevertheless, investment in

the sector has picked up as the economy recovers and oil prices have rebounded to

above $80 per barrel.

Today, the Canadian oil sands are the world’s largest energy project. Th e industry

has attracted investment from virtually every major domestic and international

oil company, totaling $200 billion in committed funds for current and proposed

projects. Alberta is home to the world’s second largest hydrocarbon basin (after

Saudi Arabia), containing 176 billion barrels of proved reserves of which 174 billion

bbls is crude bitumen and 1.6 billion bbls is conventional crude oil. In 2008, the

industry produced an average 1.3 million barrels per day (bbls/d), representing 59%

of Canada’s and 1.5% of global oil production. Growth of the oil sands industry has

enabled Canada to surpass Saudi Arabia as the United States’ largest oil supplier.

Production is expected to peak anywhere between 2.3 million bbls/d and 6.3 million

bbls/d in coming decades and potentially satisfy more than one third of projected

U.S. oil demand by 2035.3

At the same time, oil sands projects in Alberta are Canada’s fastest growing source

of greenhouse gas emissions. With continued expansion, oil sands are forecast to rise

from 5% of the nation’s total CO2 emissions to 15% by 2020, complicating Canada’s

eff orts to achieve GHG reduction goals. Since 2007, oil sands producers in Alberta

have been subject to a provincial law that imposes a CAD $15 per ton levy on

CO2 emissions. But the levy has had little demonstrable eff ect in altering oil sands

production plans. Figure A illustrates the reserves as well as production guidance and

CO2 emission estimates of major oil sands companies through 2018.

1. Dollars are expressed in U.S. currency unless otherwise noted, such as CAD $ for Canadian dollars.

2. “Oil Sands Economic Impacts Across Canada,” Canadian Association of Petroleum Producers (CAPP),

April 2008.

3. “Growth in the Canadian Oil Sands: Finding a New Balance,” Cambridge Energy Research Associates (CERA),

March 2009. [Th e range is dependent on economic and policy scenarios outlined by CERA in this report.]

Canda’s oil sands are the

world’s largest energy

project, with $200 billion in

funds committed.


Figure A. Largest Oil Sands Companies

Oil Sands Mining Reserves as % of Proved Reserves

in 2007²

Projected Production in 2018 (boe/d)

Projected GHG Emissions in

2018 (million tonnes)³

Projected Increase in Emissions

2018/20074

Suncor¹ 56% 550,000 19.1 171%

Imperial 88% 510,000 20.9 143%

Petro-Canada 48% 190,000 6.9 112%

Husky n/a 160,000 5.8 80%

StatoilHydro n/a 200,000 7.3 47%

ConocoPhillips 2% 300,150 11.1 20%

Total SA (France) n/a 259,500 8.1 14%

ExxonMobil 3% 508,800 19.3 14%

Occidental n/a 31,000 1.0 10%

Marathon 26% 48,400 1.4 9%

BP n/a 100,000 3.7 6%

Shell 9% 141,000 4.1 4%

Chevron 4% 48,400 1.4 2%

Murphy 32% 25,000 1.1 n/a

Sinopec n/a 56,667 1.7 n/a

Group Total 3,047,250 109.9

¹Th e list of largest integrated O&G companies can be expanded to include exploration & production

companies COST, CNR, Nexen/OPTI, and Cenovus.

² Th is is mining oil sands reserves only. In-situ reserves are incorporated into the conventional oil reserve

estimates. Several producers with substantial projects in the pipeline have not yet reached a stage in the

project development when proved reserves are booked.

³2018 estimates are used, as this is when the Canadian federal government targets to start regulating

emissions in oil sands projects, either by carbon sequestration or use off sets. Pembina Institute’s estimates of

projects’ carbon emissions were applied. 4Projected 2018 GHG emissions from oil sands projects are compared to actual 2007 company-wide reported

emissions

Projected Oil Sands GHG Emissions in 2018 (million tonnes)

Source: RMG, based on corporate disclosure

Imperial

ExxonMobil

Suncor

ConocoPhillips

Total SA (France)

Average

StatoilHydro

Petro-Canada

Husky

Shell

BP

Sinopec

Chevron

Marathon

Murphy

Occidential

0.0 5.0 10.0 15.0 20.0 25.0


Oil Sands Production PrimerCanadian oil sands deposits are a mixture of sand (73%), clay and silt (13%), bitumen

(10%), and water (4%). Th e ore lies above limestone and below the non-oil bearing

layer of earth called overburden, which is covered by muskeg (an acidic type of soil

common in boreal forests). Th e deposits are found primarily in Central Alberta in

three main fi elds: Athabasca, Peace River and Cold Lake.

Bitumen is a heavy crude oil that cannot be recovered through a well in its natural

state and hence needs enhanced recovery in the extraction process. Th e two main

extraction methods are conventional surface mining and in-situ (Latin for ‘in place’)

recovery using heat (steam). Approximately 20% of Alberta’s oil sands are deposited

close enough to the surface to be mined; the remaining 80% of the resource lies

deeper underground and can only be recovered through in-situ processes. Th e

mining reserves are concentrated in only 2.5% of the oil sands land area; in-situ

reserves are spread over the remaining 97.5%. In 2008, 55% of Alberta’s total 1.3

million bbls/d oil sands production came from mining, and 45% from in-situ

projects.4

Open pit mining (see Figure C below) includes excavation of the ore, initial transport

of the ore by diesel-powered trucks and secondary transport, or hydrotransport (ore

dissolved in water) to the primary extraction facility. Th ere the bitumen is separated

from sand and other compounds, using Dr. Clark’s hot water process, whereby the

sand is essentially combined with hot water to become a slurry. As a result, the

bitumen froth fl oats to the top of the separation vessel, where it is collected. Th e

residual mixture then undergoes secondary recovery, whereby smaller quantities of

bitumen are further separated from the slurry. While 50-80% of water is recycled in

this operation, the remaining mixture of sand, clay and water, along with residual

bitumen and other toxic compounds, is deposited into the waste containment areas,

known as tailing ponds.

In-situ recovery can be achieved through a variety of technologies, including steam-

assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), vapor extraction

(VAPEX), and toe-to-heel-air-injection (THAI). Th e most commonly used technique

is SAGD, whereby a series of horizontal well pairs are drilled and steam is generated

by a natural gas-fi red furnace using water from nearby aquifers. Th e steam is then

injected into the upper well, which heats up the ore and reduces the viscosity of

4. Government of Alberta, http://www.energy.gov.ab.ca/OilSands/791.asp

Figure B. Canadian Oil

Sands Deposits

Source: created by Norman Einstein, May 2006

Figure C. Oil Sands Extraction Methods

Source: Canadian Centre for Energy Information


the bitumen, enabling it to gravitate towards the lower well and fl ow towards the

surface. A large portion of the used water (70–90%) is recycled into the operation;

however, the remaining amount remains underground, where it persists as a mixture

of produced wastewater, clay and sand.

Bitumen extracted through either mining or in-situ methods is then piped to a

so-called upgrader, which is essentially an oil processing facility, where it is further

processed (i.e., upgraded) into the equivalent of conventional crude oil, or synthetic

crude oil (SCO). Th e reason for this intermediary step is to reduce the high viscosity

of the recovered bitumen, which cannot be handled by a conventional oil refi nery.

At the upgrader stage, bitumen – a complex, heavy hydrocarbon that is rich in

carbon and poor in hydrogen – is coked (stripped of a portion of carbon), distilled

(processed into various grades), catalytically converted (transformed into more

valuable petroleum forms), and hydrotreated (stripped of a portion of sulfur and

nitrogen molecules and enhanced with hydrogen).

Th e costs of existing extraction methods and upgrading processes are summarized

in Figure D. Th e impacts of fl uctuations in global commodity prices, cost of labor,

fi nancing costs and other factors aff ecting operating costs cause these estimates

to change from year to year. Th is industry snapshot taken by the Canadian Energy

Research Institute in 2008 shows representative costs for three forms of production

plus upgrading in existing oil sands projects.5

Once the bitumen has been upgraded into synthetic crude oil, it is piped to an oil

refi nery, where it is processed into fi nal petroleum products, such as gasoline, diesel,

jet fuel, petrochemicals, etc. Figure E exhibits a network of existing and proposed

natural gas and oil pipelines in North America by 2035 to facilitate synthetic crude

oil delivery. Th is includes U.S. refi neries and proposed crude oil terminals on the

Canadian West Coast in the Province of British Columbia for export to California,

Asia and elsewhere. Successful completion of this pipeline infrastructure cannot

be guaranteed, however, given many legal and regulatory challenges, including

opposition by First Nations’ and other Aboriginal communities to pipelines reaching

the Canadian West Coast.6

5. Government of Alberta, http://www.energy.gov.ab.ca/OilSands/791.asp;

Canadian Energy Research Institute (CERI), 2008 http://www.ceri.ca/

6. West Coast Environmental Law, www.wcel.org

Figure D. Operating Costs

Steam-assisted

gravity drainage

CAD $37.10/barrel

Cyclic steam

stimulation

CAD $41.94/barrel

Mining CAD $62.71/barrel

Upgrading CAD $38.75/barrel

SCO Integrated

(Mining and

Upgrading)

CAD $98.16/barrel

SCO

Source: CERI, 2008


Figure E. Proposed Pipelines for Natural Gas Supply

to the Oil Sands Industry

Source: Oil Sands Truth, and Indigenous Environmental Network


1. Macroeconomics of Oil Sands Production Analyzing the prospects for oil sands production requires a long look into the future.

Site development typically requires lead times of fi ve to eight years before the oil

starts to fl ow. Most projects are assumed to have operating lives extending up to 40

years or more. To capture relevant project dynamics, our analysis extends up to the

year 2030.

Many issues will infl uence future oil sands production volumes. Th ese include:

Global factors—oil price and supply, GDP demand growth and technology

advances

National factors in the U.S. and Canada—carbon and energy effi ciency

regulations, vehicle fuel economy standards and energy security

State and provincial factors—renewable portfolio standards and low carbon

fuel standards

Th is chapter assesses each of these infl uences and uses a multi-factor energy

forecasting model from the U.S. Energy Information Administration to make

projections of the range in possible oil sands production growth through 2030.

1.1 Price of Oil and Oil Sands Production Th e fi nancial success of Canadian oil sands production hinges on maintaining a

suffi cient global fl oor price for oil. Because oil sands production involves a number

of additional energy-intensive steps to create synthetic crude oil, it is placed at an

immediate cost disadvantage relative to conventional oil. Estimates of the required

fl oor price to recover the costs of new oil sands in-situ projects range from $65 to $95

per barrel.7 Th is is signifi cantly higher than the cost of most new oil projects involving

conventional crude. Th e collapse in global oil prices in the second half of 2008,

with prices dipping below $40 per barrel by the end of the year, demonstrated how

sensitive oil sands investment is to the macro oil price environment. More than 20

planned large-scale upstream oil and gas projects, involving around 2 mbbl/d of oil

production capacity, were deferred indefi nitely or canceled during the oil price drop;

85% of these were Canadian oil sands projects.8

Now that global oil prices have regained levels above $80 per barrel, prospects for

oil sands producers appear brighter. However, oil sands production is also vulnerable

to potential upper limits on global oil prices as well. As demonstrated by the price

spike to $147 per barrel in July 2008, high oil prices can put a drag on economic

growth and force the global economy into recession. Th is in turn leads to a decline in

commodity prices, potentially below the level where oil sands are profi table.9 High oil

7. Total S.A. (France), 2008; “Th e Peak Oil Market: Price dynamics at the end of the oil age,” Deutsche Bank,

Oct. 4, 2009; and “Canadian oil sands fi eldtrip 2009: Key takeaways,” Goldman Sachs, Nov. 19, 2009.

8. “Th e Peak Oil Market: Price dynamics at the end of the oil age,” Deutsche Bank, Oct. 4, 2009;

9. Marc Brammer and Yulia Reuter, “Th e Viability of Non-Conventional Oil Development,” Innovest Strategic

Value Advisors, Mar. 2009.


prices also stimulate investments in energy effi ciency and alternative energy sources

that further erode the demand and supply base for oil.

Generally, recessionary repercussions of a high oil price in the United States—the

largest market for oil sands production—are witnessed either at high price levels,

when domestic energy costs reach 4% of gross domestic product, or upon a rapid

price increase of 50% year over year.10 Cambridge Energy Research Associates (CERA)

produced a study in 2008 in which it identifi ed an oil price “break-point” of $120 to

$150 per barrel. As global oil prices approach these levels, various demand-destroying

factors come into play, namely energy effi ciency measures, regulatory policy

changes, innovation, alternative transportation fuels and heightened attention to

environmental concerns, which eff ectively limit any further upward pricing pressure

(see Figure G).11

Another consideration is future demand for oil itself. Deutsche Bank has forecast that

demand for oil will peak globally by around 2016.12 CERA believes that oil demand

has already peaked in the developed world.13 Such forecasts add to the argument

that oil producers may have diffi culty sustaining demand at prices above $150 per

barrel, and perhaps even at considerably lower levels.

For o il sands producers, this means that there is a relatively narrow fi nancial window

in which to operate. Th ey need oil prices to stay high enough to make a profi t—

in excess of $65-$95 per barrel—but not get so high as to reduce oil demand or

stimulate substitution by competing fuels. Th ere is reason to believe that the future

fl oor price for profi table oil sands production will be signifi cantly higher than at

present. As the world comes out of recession and the input price of commodities

such as steel begins to rise, the break-even price for new oil sands projects could

approach levels seen several years ago, when by some estimates it exceeded

10. “Oil: What Price Can America Aff ord?” Douglas-Westwood Energy Business Analysts, June 2009.

11. “Break Point Revisited: CERA’s $120–$150 Oil Scenario,” CERA Special Report, 2008.

12. “Deutsche: the end is nigh for the Age of Oil,” Financial Times, 2009.

13. “Peak Oil Demand in the Developed World: It’s Here,” CERA, Sept. 29, 2009.

Figure F. Crude Oil Price Projections through 2035

Source: U.S Energy Information Administration (EIA), 2010 Annual Energy Outlook (AEO)

$150

$125

$100

$75

$50

$2

00

8/b

bl

Light Crude Oil Price, AEO2010r

20072009

20112013

20152017

20192021

20232025

20272029

20312033

2035

Oil sands operate in a

narrow window of fi nancial

opportunity.


$100/barrel.14 In addition, other factors such as carbon pricing and mounting

environmental compliance costs may cause the eff ective fl oor price of oil sands

production to rise, even as demand-limiting factors cause the ceiling price for global

oil production to fall. As a result, oil sands’ already narrow window of opportunity

may shrink even further, especially if the United States remains its prime export

market. Should oil sands expand into growing Asian markets, which appears far from

certain at this point, the dynamics described here could change.

1.2 Price of Natural Gas and Oil Sands ProductionTh e price of oil is not the only macroeconomic consideration in converting oil

sands into synthetic crude. Natural gas is intensively used to power oil sands mining

extraction facilities and especially for in-situ steam-generators. In fact, oil sands

extraction has a comparatively low energy return on energy invested (EROEI) of

7:1, meaning it takes one unit of energy (primarily in the form of natural gas or

diesel fuel) to extract seven units of energy from bitumen. Th e energy economics

are further reduced to EROEI of 3:1 when the bitumen is upgraded and refi ned. By

comparison, conventional oil has an EROEI average of 22:1, conventional natural gas

(21:1), wind energy (18:1), geothermal (16:1), and sugarcane ethanol (8:1).15

At present, the oil sands industry consumes 4% of the natural gas produced in the

Canadian Sedimentary Basin. Th is fi gure is expected to triple between 2005 and 2015,

to 2.3 billion cubic feet of gas per day (ft3/d).16

Regulatory eff orts to address climate change and other pollution problems are

expected to further increase demand for natural gas in the transportation and

14. Scott Haggett, “UPDATE 1 — UBS says new oil sands projects need pricey crude,” Reuters, Sept. 19, 2008.

15. Peter Terzakian, “Th e End of Energy Obesity,” John Willey & Sons, Inc., 2009, p.111.

16. Statistics by Energy and Utilities Board, published by Th e Center for Energy, 2005,

http://www.centreforenergy.com/silos/NaturalGasPrices/NG-MarketDynamics.asp

Figure G. Oil Price Break Point

Source: CERA, “Break Point Revisited,” 2008


electric power sectors. Natural gas is the cleanest-burning of the fossil fuels and has

slightly less than half the carbon content of coal and only two thirds that of oil. Th ese

changing market dynamics will spur more use of natural gas in heavy duty vehicles

like trucks and buses that connect to central refueling centers. In addition, gas-fi red

power generation will also grow in place of more carbon-intensive options like coal.

Combined cycle gas turbines (CCGT) that already represent a substantial portion of

the U.S. generating fl eet will provide more baseload power generation, meaning they

will run constantly instead of just during high-demand periods.

Greater access to shale gas deposits in the United States will help spur this move

towards natural gas. Th e U.S. Energy Information Administration projects that

anywhere from 42 to 112 gigawatts (GW) of new gas-fi red power generation capacity

may be added in the United States between 2007 and 2030, with the most likely

number estimated to be around 90–100 GW. By some estimates the generating costs of

CCGT could become fully competitive with coal for base-load power generation when

CO2 allowance prices reach $13.70/ton in a fully auctioned cap and trade market.17

Th is price is at the low end of the range for estimated carbon credits, making natural

gas a go-to option for power producers seeking to reduce their carbon footprints.

Such competing demands for natural gas may leave oil sands producers searching for

other energy input options that better serve their needs. One proposed solution is

to gasify petroleum coke, a by-product of bitumen extraction process, which would

be available on-site and avoid the logistical diffi culties associated with natural gas

delivery. However, this process poses signifi cant environmental challenges and increases

carbon compliance costs due to the high-carbon nature of the gasifi cation process.

Toe-to-heel air injection (THAI) is another option that uses fi re in place of steam as an

underground heat source to draw out the bitumen. Goldman Sachs recently estimated

that successful use of the THAI process could yield savings equal to $20 per barrel if it

reduced SCO’s natural gas requirements to zero. However, use of the THAI process is

very limited at present, with one project by Petrobank producing 10,000 bbl/d.18

Nuclear power is another possible alternative to natural gas for oil sands production.

But in order to satisfy the oil sands industry’s forecasted demand for power

generation as production grows, at least 20 new nuclear power plants would need

to be constructed on oil sand leases in Alberta, which could prove to be politically

contentious.19 No oil sands producers at present have plans to make use of nuclear

power. However, Total SA reported in September 2005 that it was considering

building a nuclear plant to support its oil sands development in Alberta.20

1.3 Canadian Oil Sands and the U.S. Petroleum MarketTh e United States produced 10% of the world’s petroleum in 2008, but consumed

23% of the global supply. According to the U.S. Energy Information Administration

(EIA), transportation accounts for roughly two-thirds of U.S. petroleum

consumption, with gasoline representing almost 50% of the total volume of U.S.

17. Eric Kane and Marc Brammer, “Dong Energy: Risk Assessment for Shareholders of the Proposed 1,500 MW

Coal-Fired Plant in Greifswald, Germany,” Innovest, Nov. 2008.

18. “Canadian oil sands fi eldtrip 2009: Key takeaways,” Goldman Sachs, Nov. 19, 2009.

19. Dan Woynillowicz, “Oil Sands Fever: Environmental Implications of Canada’s Oil Sands Rush,” Th e

Pembina Institute, November 2005.

20. David Gauthier-Villars, “Total may use atomic power at oil sands project,” Wall Street Journal Europe, Sept.

2005.

Oil sands are a large and

growing consumer of clean-

burning natural gas.


petroleum products. Th is creates a key export market for foreign oil suppliers,

including Canadian oil sands producers who send most of their output to this vital

market for transportation fuels.21

In 2008, the Canadian oil sands industry produced an average of 1.21 mbbl/d,

representing 45% of total Canadian oil production and 1.5% of global oil production.

Altogether, more than two-thirds of Canadian oil production was exported to the

U.S. market in 2008, providing 1.67 mbbl/d, equal to 9% of total U.S. consumption.

Th e majority of future Canadian supply to the United States is expected to come

from synthetic crude originating in Alberta, where oil sands production may double

over the next decade and could possibly more than triple by 2030. In the United

States, oil sands are primarily concentrated in eastern Utah, mostly on public lands

where some development may be restricted. Th e estimated in-place reserve is 12 to

19 billion barrels, only about 7–11% as much as in Alberta.

Between the early 1980s and 2005, crude oil imports rose steadily in the United States,

but have since leveled off . Many energy experts believe U.S. demand for imported

crude oil has peaked. At the same time, however, U.S. oil imports from Canada

are steadily rising. In 2004, Canadian crude surpassed imports from Saudi Arabia,

Venezuela and Mexico, and now represents 23% of total U.S. imports. Th e EIA forecasts

that U.S. imports of Canadian oil will remain at 22% of total imports through 2035.

Overall, the EIA estimates that total U.S. consumption of liquid fuels, including

both fossil liquids and biofuels, will grow from 19 million barrels per day in 2008 to

22 million barrels per day in 2035. Biofuels are expected to supply all of the growth

in the liquid fuels supply, with the contribution from petroleum-based liquids

essentially remaining fl at. Th e EIA also projects that U.S. reliance on imported liquid

fuels will fall from 57% of total consumption in 2008 to 45% by 2035.22 Th is decline

would mainly result from fuel-effi ciency gains that limit U.S. demand growth in the

transportation sector as well as increased domestic production of biofuels.

21. Secondary markets include heating oil and aviation fuel.

22. EIA AEO 2010 reference case

Figure H. U.S. Crude Oil Imports, 1973–2008

Source: U.S. Energy Information Administration (EIA)

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Figure I.

Top U.S. Oil Suppliers, 2008

Source: U.S. EIA


In 2008, 95% of U.S. transportation energy came from petroleum and only 3% came

from renewables.23 Th e policy goal of the Obama administration is to accelerate a

move toward renewable fuels and energy effi ciency. Nevertheless, by 2035, the EIA

projects that conventional crude oil will remain the dominant source of supply on

global markets, representing 87% of crude oil production, with unconventional

sources like oil sands making up approximately 13% of the supply.

Looking forward, one key question facing Canadian oil sands producers is whether

they will seek to develop other major export markets beyond the United States.

Th e International Energy Agency’s 2009 World Energy Outlook projects that primary

energy demand will grow by 40% globally through 2030, with global oil demand rising

by 24% to 105 mbbl/d. While the United States is expected to remain the largest

petroleum consumer over this period, Chinese consumption is expected to overtake

the U.S. by 2045. Other growing petroleum markets include the Middle East, India

and non-OECD Asia. Favored oil suppliers for these regions include members of

the Organization of Petroleum Exporting Countries (OPEC) and Russia, which have

production in close proximity to these growing markets.

Many oil-importing countries will look increasingly to Saudi Arabia and Canada

for supply, since together they account for 33% of the world’s proven petroleum

reserves as of 2010.24 But for Canadian oil sands producers to serve these growing

export markets, new pipelines would have to extend from Alberta to Canada’s port

cities, and new refi neries would have to be built near these cities or in countries

importing the fuel. For this to happen, oil sands producers will have to overcome

considerable environmental opposition and legal challenges, especially from

First Nations communities who have signifi cant rights and protections under the

Canadian Constitution. Enbridge’s proposed Gateway pipeline to Canada’s west

23. EIA Annual Energy Review 2009, U.S. Primary Energy Consumption by Source and Sector, 2008,

http://www.eia.doe.gov/aer/pecss_diagram.html

24. EIA Country Analysis Briefs: Iran Oil, http://www.eia.doe.gov/cabs/Iran/oil.html

Figure J. Global Petroleum Consumption: 2007–2035

Source: U.S. EIA, 2010 AEO

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China

OECD Europe

Middle East

Other Non-OECD Asia

India

Canada

Oil sands are the fastest-

growing source of US oil

imports.


coast would cross the territories of 42 separate First Nations, many of whom have

expressed signifi cant opposition to the project. Several extraction companies have

been denied permits or put projects on hold because they failed to gain consent

from First Nations in the same region of British Columbia where the Gateway

pipeline would pass. In addition, coastal First Nations have objected to the pipeline,

which would bring oil tankers through their territories in order to ship the bitumen

to market. In March 2010, nine Coastal First Nations cited concerns over the lasting

and devastating eff ects of a possible oil spill in explaining their opposition to the

Gateway pipeline, and said that the Athabasca Chipewyan Cree First Nation located

near Alberta’s oil sands backed their declaration.25

Given these roadblocks to tapping other foreign markets, for the foreseeable future

output from oil sands will remain dependent on U.S. petroleum demand and global

market conditions, including potential regulations on the carbon content of fuels.

As a high cost source of supply, the oil sands will require a relatively high oil price

in order to justify continued investment in production growth. Th e U.S. Energy

Information Administration anticipates a steady rise in oil prices as the global

economy recovers—with the price per barrel expected to reach $133 by 2035 in

constant 2009 dollars. Th is report assumes that global oil prices will remain high

enough to keep oil sands production profi table, but not rise to the point where

other demand-curtailing factors would come into play. Th is report also assumes

that the United States will remain the prime market that will determine the scale

of future Canadian oil sands production. Th ese are critical assumptions, since lower

global oil prices could depress Canadian oil sands production, while sustained higher

prices and/or the opening of new export markets possibly could stimulate oil sands

production beyond the levels modeled here.

25. “First Nations Say Th ey Will Not Allow Pipelines and Oil Tankers Carrying Alberta’s Tar Sands Oil in British

Columbia,” Canada Newswire, Mar. 23, 2010.

Figure K. Petroleum Production by Region: 2007–2035


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Conv Russia

Conv US

Unconv. Canada & Mexico

Conv Mexico

Conv Canada

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20212023

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20312032

20332034

Th e US is expected to

remain the dominant export

market for Alberta’s oil

sands.


1.4 Oil Demand Constraints in the United StatesTh e remainder of this chapter explores how current and planned U.S. regulations

could aff ect future oil demand, and its possible eff ects on imports of Canadian oil

sands. Reference scenarios developed by the Canadian Association of Petroleum

Producers (CAPP) are compared against the oil demand-limiting eff ects of:

the U.S. American Recovery and Reinvestment Act (ARRA)

transportation fuel demand restrictions for U.S. federal government agencies,

including specifi cally a synfuel ban

vehicle fuel effi ciency as defi ned by Corporate Average Fuel Economy (CAFE)

standards

a federal climate change bill to reduce greenhouse gas emissions, and

Low Carbon Fuel Standards (LCFS) as defi ned in state and federal regulatory

proposals

Of these factors, our modeling results show that LCFS has the greatest potential by

far to constrain future oil sands production.

Reference Scenario for Canadian Oil Sands ProductionTh e Canadian Association of Petroleum Producers (CAPP) issued results of a survey

of Canadian oil sands producers in June 2009.26 Th e survey presents two projections

of growth in oil sands production through 2025:

a “Growth Case” that assumes a favorable investment climate for additional

capacity growth

an “Operating & Construction Case” that forecasts production utilizing only

current operations and capacity under construction

26. “Crude Oil: Forecast, Markets & Pipeline Expansions,” Canadian Association of Petroleum Producers

(CAPP), 2009.

Figure L. Oil Sands Production Projections: CAPP

Source: Canadian Association of Petroleum Producers (CAPP)

Growth In Situ

Growth Mining

Ops & Constr. Mining

Ops & Constr. In Situ

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In the Growth Case, conventional oil production in Canada falls from 41% to only

15% of total supply by 2025, while oil sands production increases from 59% to 85%.27

Th e scenarios presented in this report extend the forecast to 2030, using the same

growth rate projections as presented in the CAPP survey for 2020 to 2025. Th is makes

oil sands the increasingly dominant source of Canadian oil supply.

By 2030, in-situ oil sands production is projected to reach 2.0 mbbl/d in the Growth

scenario, and mining oil sands production is projected to reach 1.7 mbbl/d, for a total

of 3.7 mbbl/d of production. Th is compares with 1.21 mbbl/d of total production in

2008, with more than half of the production coming from mining.

In the Operating & Construction scenario, oil sands production levels off at about 2.0

mbbl/d in 2015 and maintains that level through 2030. Mining still holds a slight edge

in total production volume compared to in-situ.

It is worth noting that some forecasts of Canadian oil sands production are more

bullish than the projections presented here. In the EIA’s 2009 International Energy Outlook (IEO), oil sands production is projected to reach as high as 6.5 mbbl/d by 2030,

if oil prices climb to $200 per barrel (in 2009 dollars). Under the EIA’s reference case,

oil sands production reaches 4.2 mbbl/d by 2030, with oil at $130 per barrel. (Note

the signifi cantly greater eff ect of oil price variance on oil sands output compared with

economic growth rates projected by the EIA.) Accordingly, the Growth Scenario in this

report more closely resembles EIA’s low oil price projection, where oil sands production

achieves 3.7 mbbl/d of production by 2030, with oil prices at only $50 per barrel. We

believe the low oil price scenario put forth by EIA to be unlikely, given the EIA’s 2010

AEO oil price projections. As a result, the modeling assumptions used in this report—

and CAPP Growth forecast on which they are based—may be viewed as conservative

in relation to the EIA reference case, which forecasts an additional 500,000 bbl/d of

production by 2030, to 4.2 mbbl/d, with oil at $130 per barrel.

27. Th is breakdown excludes Canadian pentanes and condensate production.

Figure M. Oil Sands Production Projections: U.S EIA


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Low Oil Price

High Economic Growth

Low Economic Growth

19902006

20072010

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Oil sands production could

more than triple by 2030.


ARRA Eff ectTh e economic recession that struck the United States in late 2007, followed by oil

prices reaching a peak of $147 per barrel in July 2008, has resulted in a substantial

drop in U.S. oil consumption—falling from 18.2 mbbl/d in 2006 to just 15.8 mbbl/d

in 2009, a nearly 13% decline. Th e American Recovery and Reinvestment Act

(ARRA) passed by Congress in February 2009 includes measures both to stimulate

the economy (and hence energy demand) in the near term, while also promoting

energy conservation and greater use of alternative fuels over the longer term. Th ese

domestic measures in turn have implications for the CAPP forecast, given that more

than two-thirds of Canadian oil is exported to the U.S. market. Potential demand-

limiting measures of ARRA include:

weatherization and assisted housing

energy effi ciency and conservation block grant programs

support for state energy programs

tax credits for plug-in hybrid and electric vehicles and for renewable electricity

generation; loan guarantees for renewables and biofuels

support for carbon capture and storage (CCS), and

smart grid expenditures

Our review of ARRA fi nds only a minimal net impact on oil sands production,

reducing the CAPP Growth forecast by 0.5-2.0% over the measurement period. (In

Figure N, this is depicted as the diff erence between the AEO09 NO STIM and AEO09

STIM chart lines.) Th is slight change is to be expected as many of the energy provisions

of ARRA address the building sector rather than the transportation sector. EIA has

since updated its forecast, taking account of the ARRA stimulus package (depicted

as AEO10 STIM in the chart). Th e new forecast projects a more rapid and smoother

economic recovery whereby the stimulus does more to spur energy demand than

the energy conservation measures do to constrain future petroleum demand. Th e

updated EIA projections are more in line with the CAPP Growth scenario.

Figure N. U.S. Oil Demand Projections under ARRA

Source: U.S. EIA, 2009 AEO and 2010 AEO

AEO10 STIM

AEO09 NO STIM

AEO09 STIM

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Other Federal Demand-Reducing Measures for Transportation FuelsSeveral additional federal regulations specifi cally target demand reductions for

liquid fuels in the U.S. transportation sector. Th ese include Corporate Average Fuel

Economy (CAFE) standards, proposed support for electric vehicles under H.R. 2454

American Clean Energy and Security Act (ACES), regulations reducing Federal agency

demand for high-carbon transportation fuels, and Low Carbon Fuel Standards (LCFS)

at the state, regional and federal level. Th is section evaluates the impact of these

measures on the market for oil sands oil in the U.S. market.

Mandates to Reduce Demand for Transportation FuelsIn April 2010, the Obama administration approved new CAFE and greenhouse gas

(GHG) emission standards developed jointly by the EPA and the National Highway

Transportation Safety Administration. By 2016, new passenger cars will need to

reach 39 miles per gallon (mpg), and light trucks 30 mpg, with standards developed

for each vehicle class size, equal to 35.6 mpg for the 2016 combined new vehicles

fl eet. (Th e current combined CAFE standard is slightly more than 25 mpg.) Th e

program also imposes a fl eet wide limit of 250 grams CO2 equivalent by 2016, a 26%

improvement over the average for 2009 model year light-duty vehicles. Th is federal

rule supersedes a California law that would have taken eff ect in 2012, with similar

GHG emission targets. It is projected to save 1.8 billion barrels of oil over the life

of cars and trucks sold between the 2012-16 model years as a result new vehicles’

improved fuel effi ciency. Th e federal rule is more ambitious than an earlier target of

not less than 35 mpg for the combined fl eet of cars and light trucks by model year

2020, approved by Congress as part of the 2007 Energy Independence and Security

Act (EISA).

Many factors infl uence the eff ect of CAFE standards on overall demand for

transportation fuels. Th ese include:

Th e size and composition of the U.S. transportation fl eet (currently 90% light-

duty passenger vehicles, 2% commercial light trucks, and 8% freight trucks;

commercial and freight trucks are not subject to the CAFE standard)

Annual vehicle miles traveled (VMT)—a refl ection of both U.S. fl eet

composition and driving behavior

Mileage effi ciency achieved (CAFE) in each vehicle category

Th e average age of vehicles on the road relative to new vehicles sold (i.e., fl eet

turnover rate)

Gasoline consumption as a percentage of total U.S. petroleum consumption has

been declining at about 0.2% per year since 1949, when EIA records began. For our

modeling purposes, we assume that transportation will continue to account for 65%

of U.S. petroleum consumption through 2030. However, recent trends suggest that

transportation demand may decline to 59% of petroleum consumption as renewable

fuels and effi ciency measures off set some of this market.

Key to this forecast is a projection of the size of the U.S. motor vehicle fl eet. In 2009,

the U.S. fl eet shrank for the fi rst time, dropping to 246 million vehicles from a peak

of 250 million in 2008, as vehicle scrappage rates (14 million cars) exceeded new


vehicle sales.28 Th is is a refl ection of the recent economic recession and the steep

increase in gasoline prices in 2008. In 2009, 10.4 million cars and trucks were sold

in the U.S., down from 13.5 million in 2008 and a peak of 17.8 million in 2000.29 Th e

last time vehicle sales were this low was in 1980. Vehicle sales are expected to revive

as the economy improves and gasoline prices remain below the peak of $4.10 per

gallon reached in July 2008. Nevertheless, market saturation, energy pricing trends,

environmental concerns and a generational shift away from cars could extend this

overall decline.

Our model assumes a 1% annual reduction in annual U.S. vehicle sales through

2030. At the same time, we project that the entire U.S. fl eet (light duty, commercial

truck and freight), weighted by the percent miles traveled in each category, will

achieve a combined 33 mpg by 2020 and 35 mpg by 2030. Th is equates to an annual

fuel effi ciency increase of 1.6% for the entire U.S. ground transportation fl eet.

However, this may be largely off set by a projected 1.5% average annual increase in

total U.S. fl eet vehicle miles traveled (VMT). Under these assumptions, petroleum

consumption in the transportation sector would remain largely constant, with

increases in VMT off setting most of the fuel economy gains and reductions in the U.S.

vehicle fl eet.

28. “U.S. Car Fleet Shrank by Four Million in 2009 — After a Century of Growth , U.S. Fleet Entering an Era of

Decline,” Earth Policy Institute, Jan. 6, 2010.

29. “U.S. Car and Truck Sales, 1931–2008,” Ward’s Automotive Group, “WARDS U.S. Light Vehicle Sales by

Company,” Ward’s Automotive Group, Jan. 5, 2010.

Figure O. U.S. Vehicle Sales and Fleet Size: 1961–2009

Source: U.S. National Highway Transportation Safety Administration

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Mandates to Decrease Federal Government Oil ConsumptionSection 526 of the 2007 Energy Independence and Security Act (EISA) prohibits

U.S. Federal agencies from procuring unconventional transportation fuels—a.k.a.

“synfuels”—unless they have life cycle GHG emissions that are less than those from

conventional petroleum sources. Synfuels, in general, refer to fuels processed from

bituminous sands, oil shale, coal gas, and biomass. Historically, the Federal government

has accounted for 2.52% of total annual U.S. petroleum consumption, with the

majority coming from the Defense Department and military operations. Accordingly,

application of Section 526 could eliminate a small portion of the Canadian oil sands

market that otherwise would be available to supply the U.S. Federal government.

Furthermore, an Executive Order by the Obama administration in October 2009,

titled “Federal Leadership in Environmental, Energy and Economic Performance,”

requires a 30% reduction in Federal agency vehicle fl eet petroleum use by 2020, equal

to a 3% annual reduction starting in fi scal year 2010.30 Th is order will place more

downward pressure on petroleum demand from the U.S. Government, beyond the

synfuel restrictions imposed by Section 526 of EISA.

Th e climate bill passed by the U.S. House of Representatives in June 2009, known as

the American Clean Energy and Security Act (ACES), also provides strong support for

the development of electric vehicle infrastructure and manufacturing. Th is includes

the allocation of emission allowances for investment in clean vehicles and further

incentives in the form of loans for advanced technology vehicle manufacturing.

Moreover, in Sections 121 to 130, ACES provides further development of alternative

fuel vehicles after 2016. Additionally, Section 130A provides research incentives for

greater use of natural gas in transportation to decrease GHG emissions. Each of these

measures, if adopted in fi nal climate legislation, would further reduce U.S. demand

for liquid petroleum fuels in the transportation sector.

To assess the impact of such legislation and the more stringent CAFE standard of

35 mpg by 2016 issued by the Obama administration, the EIA has conducted an

analysis in response to a request from U.S. Representatives Henry Waxman (D-Calif.)

and Edward Markey (D-Mass.), the prime sponsors of the House ACES bill. Th e EIA

analysis also takes account of the ARRA legislation passed by Congress in February

2009. Th e results of this analysis have been included in our model to account for the

eff ects on the CAPP Growth forecast for oil sands production through 2030, and are

shown in Figure P. Th e combined eff ect of the accelerated CAFE standard, support

for clean vehicle development, and other provisions of a potential climate and energy

bill approved by Congress would put further downward pressure on U.S. petroleum

demand, which in turn could reduce the CAPP projections. However, the net eff ect

is relatively modest, with the reduced U.S. demand slowing oil sands production to

an annual rate of 5.0% through 2030 rather than at a rate of 5.6% under the CAPP

Growth forecast. Th is means that by 2030, oil sands production would reach only 3.5

mbbl/d, rather than 3.7 mbbl/d under the CAPP Growth forecast, a reduction of 7%.

As discussed in the next section, the imposition of Low Carbon Fuel Standards could

have a much greater impact on future oil sands production.

30. “Federal Leadership in Environmental, Energy and Economic Performance,” Th e White House, Oct. 5, 2009.

http://www.whitehouse.gov/assets/documents/2009fedleader_eo_rel.pdf

“President Obama Signs an Executive Order Focused on Leadership in Environmental, Energy and Economic

Performance,” Th e White House, Oct. 5, 2009. http://www.whitehouse.gov/the_press_offi ce/President-Obama-

signs-an-Executive-Order-Focused-on-Federal-Leadership-in-Environmental-Energy-and-Economic-Performance/

Federal programs to reduce

fuel and greenhouse gas

emissions may have only a

modest eff ect in reducing

demand for oil sands; Low

Carbon Fuel Standards

could have a much greater

impact.


1.5 Low Carbon Fuel StandardsLow Carbon Fuel Standards (LCFS) aim to regulate and reduce the carbon intensity of

transportation fuels in a comprehensive way, using the life cycle of the fuel on a “fi eld-

to-wheels” basis. Th ese standards provide incentives to reduce greenhouse gas (GHG)

emissions at the extraction, processing and distribution stage of the fuel, or what is

called “fi eld-to-pump.” At the “pump-to-wheels” stage, refi ned oil sands products have

the same carbon intensity as conventional gasoline per gallon consumed.

LCFS is being considered as regulatory tool both to reduce GHG emissions as well as

dependence on foreign oil. It is being adopted as a climate change mitigating strategy

in the United States, Canada and the European Union.

California led the way with the passage of the California Global Warming

Solutions Act of 2006 (Assembly Bill 32). To implement this bill, the state

legislature required the California Air Resources Board (CARB) to adopt a list

of discrete, early action GHG emission reduction measures to be implemented

and enforced by no later than Jan. 1, 2010. In 2009, CARB adopted an LCFS in

which the average carbon intensity of transportation fuels used in California

must be reduced by 10% by 2020. Initial progress under this LCFS standard

must be reported to CARB in 2011.

Other states are following California’s example. Eleven Northeastern and Mid-

Atlantic states31 (from Maine to Maryland) have agreed to develop a regional

LCFS, with the framework to be fi nalized by early 2011.32 Together, these states

31. Maine, Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island, New York, New Jersey,

Pennsylvania, Delaware and Maryland

32. Northeast States for Coordinated Air Use Management (NESCAUM), http://www.nescaum.org/topics/

low-carbon-fuels

California adopted a Low

Carbon Fuel Standard in

2009.

Figure P. Impact of Current U.S. Regulations on

Oil Sands Production through 2030

Source: RiskMetrics Group, referencing CAPP 2009 forecast and EIA 2010 EAO

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and California comprise approximately 25% of the U.S. transportation fuel

market.

Th e Midwestern Governors Association (MGA) has also adopted an Energy

Security and Climate Stewardship platform that includes a commitment

to create a uniform, regional low-carbon fuels policy to be implemented at

the state or provincial level. (Ten governors and one Canadian premier have

endorsed this proposal.) Th e Midwestern states represent the Canadian oil

sands’ largest export market, with three dedicated pipelines extending from

Alberta into the Upper Midwest. Th e MGA seeks to have agreement on the

proposed rule in 2010.33

Th e Western Climate Initiative, including seven states and four Canadian

provinces, is also developing an LCFS, as is Ontario. In 2009, Oregon committed

to develop an LCFS standard, and British Columbia has adopted an LCFS

framework that modeled on the California regulation.

Finally, the U.S. Conference of Mayors adopted a resolution in the summer of

2008 asking for the creation of “guidelines and purchasing standards to help

mayors understand the lifecycle greenhouse gas emissions of the fuels they

purchase.” While not a legislative requirement, this resolution signals additional

support for LCFS as a climate change mitigation strategy.

Given these developments at the state and regional level, it is possible that more

than 50% of the U.S. market could become subject to LCFS requirements in the years

ahead, even if a federal standard is not adopted. Indeed, lack of legislative progress in

Washington could accelerate such state- and regional-level action.

Compliance with LCFSAt present, conventional gasoline has an average carbon content of 520 kilograms

of carbon dioxide equivalent per barrel of crude on a fi eld-to-wheels basis. (Of these

emissions, about 420 kg of CO2e/barrel34 occur at the pump-to-wheels stage as the

fuel is burned.) To meet the LCFS as set forth under the California rule, the carbon

intensity of conventional gasoline must be reduced by 10% to approximately 468 kg

of CO2e/barrel on a fi eld-to-wheels basis by 2020.

Th e carbon intensity of oil sands is signifi cantly higher than conventional crude oil,

given the additional energy required to extract, upgrade and refi ne the fuel at the

fi eld-to-pump stage of production. As shown in Figure Q, oil sands mining operations

produce 47% more emissions on average than gasoline at the fi eld-to-pump stage

(and 9% more emissions on a fi eld-to-wheels basis). In-situ operations produce up to

80% more emissions at the fi eld-to-pump stage (and up to 15% more emissions on a

fi eld-to-wheels basis).

Assuming that oil sands from mining and in-situ operations are combined after the

upgrading stage for delivery to the U.S. market, the average carbon content of these

fuels is 582 kg of CO2e/barrel on a fi eld-to-wheels basis. Th is represents 12% greater

carbon intensity than conventional gasoline, with a carbon content of 520 kg of

33. Th e states include Wisconsin, Minnesota, Illinois, Indiana, Iowa, Michigan, Missouri, Kansas, Ohio & South

Dakota.

34. Carbon dioxide equivalent refers to the potency of a mix of major greenhouse gas emissions relative to

CO2. It is a means of creating a single unit for all greenhouse gas emissions.

Gasoline produced from

oil sands has 12% higher

carbon intensity on average

than conventional gasoline.


CO2e/barrel. In order to achieve the LCFS as defi ned under the California rule, an

additional 10% reduction would be required resulting in a carbon dioxide content

of 468 kg per barrel. Th is works out to a total average reduction of 114 kg of CO2e/

barrel for Canadian oil sands, equal to a 19.6% reduction in carbon intensity on a

fi elds-to-wheels basis.

Th e California LCFS rule requires any producer or supplier of transportation fuels to

the California market to meet incrementally lower carbon intensity targets so that

the 2020 target average of 468 kg of CO2e/barrel is achieved over time. A regulated

party can meet these annual requirements with any combination of fuels they

produce or supply (including the sale of electricity and natural gas as transportation

fuels), by lowering emissions in the production process or by applying LCFS credits

acquired in previous years or purchased from other regulated parties. Regulated

parties must report their performance to CARB annually starting in 2011. Th e

aircraft, rail and marine sectors are not regulated under the California LCFS.

Th ese rules have important implications for the availability and use of carbon off sets

as LCFS credits. By creating a cap-and-trade style market for transportation fuels,

LCFS credits encourage technical innovation in oil production and throughout

the transportation supply chain. Most important, the availability of these credits

stimulate demand for electricity, natural gas and renewable fuels as alternatives to

petroleum in the transportation market. Th e next section examines these credits in

greater detail.

LCFS CreditsTh e use of LCFS credits obtained through transportation emissions reductions provides

a number of opportunities for oil sands producers to achieve the goals of this carbon

regulation. In eff ect, each barrel of oil sands needs approximately one-ninth of a ton

(114 kg) of CO2 reductions to comply with the 468 kg of CO2/barrel limit set by the

California rule for 2020. Put another way, each ton of CO2 reductions achieved through

the purchase of LCFS credits would enable roughly nine barrels of oil sands production

Figure Q. Carbon Emissions Intensity of Oil Sands Mining and In-situ

Processes

Fuel Type

Life Cycle Phase (kg CO2e/bbl crude) Total

Vehicle Combustion % of LCA

Field to pump % of LCA

Field to wheels

Average US bbl consumed 420 81% 100 19% 520

SAGD SCO 420 70% 180 30% 600

% more intensive 80% 15%

SAGD Dilbit 420 71% 175 29% 595


Mining SCO 420 74% 147 26% 567


Source: RiskMetrics Group, referencing “Growth in the Canadian Oil Sands,” IHS and CERA, 2009.

Oil sands would need to

reduce their carbon intensity

in gasoline by 20% to meet

the California LCFS.


(mining and in-situ combined) under the California standard in 2020. In turn, each $10

increment in the price per ton of these credits would raise the delivery cost of oil sands

by about $1.14 per barrel. A $100 price per ton in 2020, for example, would increase the

average delivery cost of oil sands by $11.40 per barrel. Hence, the purchase of such LCFS

credits would be a viable compliance option for oil sands producers as long as global oil

prices were high enough to absorb this eff ective price increase.

Canada’s oil sands producers are prodigious emitters of carbon dioxide, however,

and would need to purchase a substantial amount of off sets if they were to rely on

this approach. Altogether, oil sands producers are Canada’s fastest growing source of

GHG emissions, with their emissions projected to rise from 5% to 15% of the nation’s

total emissions by 2020. It is unclear whether a carbon trading market can emerge

that would grow fast enough to sustain the level of off sets that Canadian oil sands

producers would require.

With respect to purchasing LCFS credits, the pool of available off sets may be

further restricted by regulations set forth under state standards. As noted above,

the California LCFS limits the creation of off sets and credits to other parties within

the transportation sector, where GHG reductions are generally more expensive to

achieve than in other sectors (such as power generation and industrial production).

Such a limited pool and higher allowance prices could especially disadvantage

oil sands producers, whose average production costs are already higher than for

conventional oil producers.

In addition, conventional petroleum producers would need to purchase proportionately

fewer off sets to meet the LCFS requirements, since they face a 10% average carbon

reduction requirement vs. a 20% average reduction for oil sands producers. Given that

conventional oil providers represent a much larger portion of the petroleum market,

with lower marginal costs on a per-barrel basis to achieve compliance through off set

purchases, they potentially could buy up the market for applicable transportation

sector credits and leave oil sands producers with only the most expensive purchase

options—or possibly none at all. Th e terms of the California LCFS makes this scenario

more likely with its limitations on emissions trading to parties within the transportation

sector. Th e Northeast states are still deciding how they would defi ne the market for

LCSF credits, but tend to follow California’s lead on matters like this.

Carbon Capture and SequestrationTh e use of carbon capture and sequestration (CCS) is another off set option available

to oil sands producers. With respect to achieving compliance with LCFS, the formula

for calculating the off sets is the same as described above. For each ton of CO2

sequestered through CCS technology, roughly nine barrels of refi ned oil sands could

meet the LCFS requirements as defi ned under the California rule in 2020. Th erefore,

CCS also could be an attractive compliance option if its market price is less than

that of other LCFS credit options. At present, however, CCS remains an unproven

technology at a commercial scale in Alberta, with estimated costs ranging from CAD

$70-$150 per ton of CO2 sequestered.35

35. “Carbon capture to cost $3 billion a year to succeed,” Daily Oil Bulletin, July 25, 2009. [Article cites an

estimate by Jim Carter, former president Syncrude Canada.]

A $100 price/ton for LCFS

credits would raise the

delivery costs of oil sands by

$11.40 per barrel.


In addition, Alberta’s oil sands are not in a favored geographic location for carbon

sequestration. Extensive pipeline networks would have to be built to ship the CO2

to underground reservoirs located up to 1,000 miles away, where the CO2 could be

used to enhance oil recovery from mature Canadian oil fi elds. Further, a host of legal,

regulatory and permitting issues still would have to be overcome. Liability issues

present a particular challenge, since the sequestered carbon would need to remain

safely stored for hundreds or even thousands of years. It is unclear whether private

corporations or insurers could off er such centuries-long assurances.

A study by RAND Corp. suggests that if CCS can be demonstrated successfully at a

commercial level, it would add $3-6 per barrel to costs of oil sands mining operations

and $4-9 per barrel for in-situ operations.36 However, a key assumption made in

this study is that 85% of all “well-to-pump” emissions associated with oil sands

production would be captured. In reality, most CO2 emission streams associated with

oil sands production are diff used throughout the production process. It is far more

likely that producers would focus on the portions of their operations yielding high

concentrations of CO2, such as upgrading and hydrogen processing that account for

only 10-30% of total upstream emissions.

Th e Province of Alberta is weighing a policy that would require oil sands upgrader

facilities to operate CCS-ready facilities after 2018 for projects that come onstream

after 2012. Th is still would leave Canadian oil sands producers on a high emissions

growth trajectory as their production expands. Even with a higher CO2 capture

rate of 30-50% by 2050, the “well-to-pump” emissions from growing oil sands

production could exceed the entire carbon budget for Canada recommended by the

Intergovernmental Panel on Climate Change, which calls for an 80% reduction in the

nation’s overall emissions by 2050.37

Meanwhile, since 2007 the Alberta government has imposed a CAD $15/ton

levy on CO2 emissions and made CAD $2 billion available to support commercial

demonstration of CCS technology. However, neither the “carrot” of funding support

nor the “stick” of the levy has prompted much CCS activity among Canadian oil sands

producers. In fact, eight producers withdrew bids for a share of this government

support in 2009. Th is leaves the Athabasca Oil Sands Partnership, operated by Royal

Dutch Shell, (with 20% minority stakes held by Chevron Canada Ltd. and Marathon

Oil Sands L.P.), as the only oil sands producer to participate in this subsidy program.

Th e proposed Quest CCS project, receiving CAD $745 million in government funding,

would be located at Shell’s Scotford Upgrader, near Fort Saskatchewan, Alberta.

Alberta’s CCS Task Force estimates that the initial cost of CCS at oil sands upgraders

and hydrogen facilities is in a range of about CAD $75 to $115/ton of CO2, taking into

account a $15–20/ton levy on CO2 emissions.38

36. Michael Toman, et. al., “Unconventional Fossil Fuels: Economic and Environmental Tradeoff s,” RAND

Corp., Technical Report 580, 2008. [Sponsored by the National Commission on Energy Policy.]

37. “Carbon Capture and Storage in the Alberta Oil Sands — A Dangerous Myth,” World Wildlife Funk (UK)

and Th e Co-operative Bank, October 2009. [Th e referenced projection for 2050 assumes that Canadian oil

sands production reaches 5.8 mbbl/d at that time.]

38. “Accelerating Carbon Capture and Storage in Alberta,” Alberta Carbon Capture and Storage Development

Council, Interim Report, Oct. 2008.

Carbon capture technology

is costly and unproven at

commercial scale.


Renewable Fuel StandardsOne other carbon mitigation option available to high-carbon crude producers such

as oil sands is to blend their fuel with low-carbon renewable fuels in order to meet

LCFS requirements. To date, most low-carbon fuels are made from blending with

biomass-based feedstocks, such as corn-based ethanol. However, depending on the

energy and production processes used to make corn-based ethanol, this option may

not provide a suffi cient reduction in carbon intensity to meet the LCFS standard.

Accordingly, the viability of this option for oil sands producers depends largely on the

development of advanced biofuels that off er greater carbon reduction opportunities,

such as cellulosic ethanol.

Th e U.S. Renewable Fuel Standard (RFS), adopted in 2005, promotes the use of biofuels

as a way to reduce dependence on foreign oil. Th e RFS initially called for the production

of 7.5 billion gallons of biofuels to be produced by 2012. Under the Energy Independence

and Security Act (EISA) of 2007, an additional target of 36 billion gallons of annual

biofuels production by 2022 was established. Th e EPA has developed a Renewable

Fuel Standard 2 (RFS2) program with specifi ed annual volume standards for biofuels

with substantially reduced carbon intensity. Th ese include cellulosic biofuels, biomass-

based diesel, other advanced biofuels and other renewable energy options for use in the

transportation sector. Th e revised RFS2 was fi nalized in February 2010, with an eff ective

date of July 1, 2010, and applies to all biofuels produced or imported in 2010.39

Starting from low production volumes in 2009 (estimated 9 billion gallons of mainly

corn- and soy-based ethanol), this target eventually will rise to the 36-billion gallon

requirement by 2022, as set forth under EISA. Hence, RFS2 should substantially

increase the volumes of low carbon biofuels available for blending. According to EPA,

RFS2 should enable biofuels to represent about 7% of expected annual gasoline and

diesel volume in 2022.

Advanced low carbon biofuels—such as cellulosic ethanol from crop residues and

wood stalks, and advanced biofuels derived from algae—have been targeted to meet

the higher volume requirements. Th e EPA’s plan calls for corn-based ethanol to be

capped at 15 billion gallons a year by 2015, while cellulosic ethanol is scheduled to

grow to 16 billion gallons annually by 2022, providing nearly half of the volume for

the RFS2 target.

To qualify as a viable low carbon fuel substitute, biofuels under the RFS2 must

achieve at least a 20% percent reduction of total life cycle GHG emissions (kg CO2e/

bbl) relative to the average conventional gasoline or diesel available in 2005.40 For

oil sands that face the LCFS requirement in the United States, both the volume and

39. “EPA Issues Final RSF2 Rule,” Evolution Fuels, Feb. 2, 2010.

http://www.evolution-fuels.com/Blog.aspx?Id=125

40. Biofuels that fulfi ll the lifecycle GHG emissions reductions include: ethanol produced from corn starch

at a new (or expanded capacity from an existing) natural gas-fi red facility using advanced effi cient

technologies that we expect will be most typical of new production facilities that complies with the

20% GHG emission reduction threshold; biobutanol from corn starch that complies with the 20% GHG

threshold; ethanol produced from sugarcane that complies with the applicable 50% GHG reduction

threshold for the advanced fuel category; biodiesel from soy oil and renewable diesel from waste oils, fats,

and greases that complies with the 50% GHG threshold for the biomass-based diesel category; Diesel

produced from algal oils complies with the 50% GHG threshold for the biomass-based diesel category;

cellulosic ethanol and cellulosic diesel (based on currently modeled pathways) that comply with the

60% GHG reduction threshold applicable to cellulosic biofuels. [source: http://www.epa.gov/OMS/

renewablefuels/420f10007.htm]

Ambitious targets have been

set to increase production

of advanced, low-carbon

renewable fuels.


carbon intensity of renewable fuels must be taken into account. Th ese also become

key parameters for our modeling of RFS2 through 2030.

First, our model derives an annual growth rate for each fuel category in the RFS

(cellusic biofuel, biomass-derived diesel, advanced biofuel and a general renewable

fuel category) based on EPA-mandated requirements.41 We extend estimated

volumes (in billions of gallons) of renewable fuels for each category to 2030, based

upon the last fi ve-year average annual projected growth rate in RFS2 (2018-2022).

Th e general renewable fuel category (achieving a 20% reduction in GHG content) is

phased out by 2022, as production targets for cellulosic and other advanced biofuels

are predicted to expand. For biomass-based diesel, we leave the volumes steady at 1

billion gallons. Th is provides an estimate of the total volume of low carbon renewable

41. Th e EPA will review performance to the standard each year both in terms of volumes achieved annually

and actualized GHG reductions.

Figure R. Renewable Fuel Standard Volume Requirements: 2008–2030

Renewable Fuel Volume Requirements for RFS2(% potential reductions in CO2e/bbl)

Year

Cellulosic biofuel

requirement

Biomass-based diesel requirement

Advanced biofuel

requirement

Biofuels at 20% minimum

reduction

Total renewable fuel requirement

2008 0.00% 0.00% 0.00% 20.00% 20.00%

2009 0.00% 2.25% 2.70% 18.02% 22.97%

2010 0.03% 4.44% 3.67% 16.75% 24.88%

2011 1.08% 2.87% 4.84% 16.56% 25.34%

2012 1.97% 3.29% 6.58% 15.39% 27.24%

2013 3.63% 3.02% 8.31% 14.26% 29.21%

2014 5.79% 2.75% 10.33% 12.84% 31.71%

2015 8.78% 2.44% 13.41% 10.73% 35.37%

2016 11.46% 2.25% 16.29% 8.76% 38.76%

2017 13.75% 2.08% 18.75% 7.08% 41.67%

2018 16.15% 1.92% 21.15% 5.38% 44.62%

2019 18.21% 1.79% 23.21% 3.93% 47.14%

2020 21.00% 1.67% 25.00% 2.33% 50.00%

2021 24.55% 1.52% 27.27% 0.30% 53.64%

2022 25.26% 1.32% 27.63% 0.00% 54.21%

2023 25.90% 1.32% 27.09% 0.00% 54.32%

2024 26.55% 1.32% 26.56% 0.00% 54.42%

2025 27.19% 1.33% 26.01% 0.00% 54.53%

2026 27.84% 1.33% 25.47% 0.00% 54.64%

2027 28.49% 1.33% 24.93% 0.00% 54.75%

2028 29.14% 1.33% 24.39% 0.00% 54.86%

2029 29.79% 1.33% 23.84% 0.00% 54.97%

2030 30.45% 1.33% 23.30% 0.00% 55.07%

Source: RiskMetrics Group, referencing U.S. Environmental Protection Agency fi gures

Cellulosic ethanol has 60%

lower carbon intensity than

gasoline, but it is not yet

commercially available.


fuels that would be available for blending on an annual basis for high carbon oil sands

crude to comply with the California LCFS.

As higher volumes of renewable fuels with ever lower carbon intensity enter the

market, the average reduction per barrel to be achieved through blending would

increase. Based on the biofuel volumes projected under RFS2, by 2022 production of

cellulosic, biodiesel and other advanced biomass fuels could achieve a 54% average

reduction in kg CO2/barrel relative to gasoline for oil sands producers that pursue

this blending strategy. Because most of the advances come early in the measurement

period, our model assumes only a modest further reduction in carbon intensity after

2022, so that the average reduction per barrel reaches 55.1% by 2030. Th e average

reduction in carbon intensity of renewable fuels over the entire modeling period is

shown in Figure S.

To assess how much oil sands crude can be sold in the U.S. transportation fuels

market, our model evaluates the optimal fuel mix that would be required to achieve

annual compliance with LCFS, as determined by the EPA’s RFS2, with the blended mix

achieving the mandated 10% reduction in per barrel carbon intensity by 2020 (i.e.,

468 kg of CO2e/bbl). Our model assumes equal reductions in carbon intensity each

year, whereas the California standard requires only moderate reductions in initial

years with accelerated reductions in the fi nal years. Th is has the eff ect in our model

of slightly overestimating the impact on oil sands blending requirements in the

early years, while slightly underestimating the impact as 2020 approaches. Th e total

impact over the period is comparable, however.

Our model further assumes that the carbon intensity of oil sands production and

conventional petroleum fuels will not change over the study period. However, as

more oil sands comes from in-situ production sites, and more conventional oil

comes from fi elds with heavy oil rather than light crude, the carbon intensity of all

petroleum fuels could increase.

Figure S. Projected Carbon Intensity under LCFS through 2030

Source: RiskMetrics Group, assuming 20% reduction in carbon intensity

600

500

400

300

200

100

0

20102012

20182026

20282016

20222024

20142020

2030

kg of CO2/bbl

A 20% reduction in carbon

intensity of gasoline

would reduce emissions to

approximately 420 kg per

barrel produced in 2030.


Given this concern, our model also assumes that from 2021 to 2030, an additional

10% reduction will be required under the LCFS, on top of the reduction targeted

for 2011 to 2020. Th is would result in a total 20% reduction in CO2e kg/bbl to be

achieved over the 20-year period. Incremental reductions would be required each

year to yield an average level of 421 kg of CO2e/bbl by 2030. (Th e California LCFS

has not set reduction requirements beyond 2020.) As noted above, our model also

estimates that a modest 1.1% reduction in the carbon intensity of advanced biofuels

would occur between 2022 and 2030, allowing for a 55.1% average reduction in the

overall carbon content relative to conventional gasoline by 2030.

Finally, to determine the maximum impact of the LCFS, our model assumes that the

California standard could be implemented by all 50 states, with the fi rst emissions

reductions reported in 2011. Th e sensitivity analysis below also evaluates the eff ects

of having smaller fractions of the U.S. transportation market implementing the

California standard.

With the mandated reduction in carbon intensity rising each year under the LCFS, the

proportion of renewable fuels required for blending with oil sands crude should rise

each year. At the same time, the carbon intensity of available renewable fuels should

decline over time, so that the blending requirement is reduced over time. Our model

takes account of these two countervailing factors and shows the eff ect on oil sands

blending requirements in Figure T. Starting with modest blending requirements as the

LCFS goes into eff ect in 2011, the portion of renewable fuels blended with oil sands

crude is projected to reach 39% by 2020. By 2030, the renewable fuel requirement

reaches 48% of the total blend, assuming an additional 10% reduction in the carbon

intensity of transportation fuels between 2021 and 2030.

Figure T. Projected Blend of Oil Sand and Renewable Fuels under LCFS


100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

20102011

20122018

20262028

20162022

20242014

20202013

20152017

20192021

20232025

20272029

2030

Pe

rce

nt

Ble

nd

fo

r O

il S

an

ds

RF

Oil S

an

ds

Renewable fuels could

account for nearly half of

the blend with gasoline

derived from oil sands by

2030.


Th us, if Canadian oil sands producers were to rely exclusively on renewable fuels

blending to meet requirements of a nationwide U.S. LCFS, with a 20% reduction in

carbon intensity by 2030, their portion per barrel of the blended fuel would fall to

52%. Renewable fuels would take the place of this potential oil sands production

volume. Assuming that 65% of Canadian oil sands exports to the United States are

still devoted to the transportation market, the net eff ect would be to reduce total

production volumes by one-third as of 2030. Comparing this with the CAPP Growth

forecast, the annual average growth rate from 2010-2030 would fall from 5.6% per

year to 3.4% per year (also taking into account the demand-reducing measures

discussed earlier).

In terms of production volume for advanced biofuels meeting RFS2, our model

projects that 1.2 million barrels per day would be available for blending in 2011. By

2030, advanced biofuel production volume could rise to 8.2 mbbl/d. Th is is more

than twice as much as the amount of advanced biofuels that oil sands producers

would require to meet an LCFS adopted by all 50 states, with the average reduction

in carbon intensity rising from 10% in 2020 to 20% by 2030.

However, it should be noted that oil sands will also be competing with conventional

gasoline to achieve the LCFS requirements. With current projections that

conventional gasoline will continue to supply approximately 87% of the U.S.

transportation market in 2030, its demand for blended renewable fuels is likely to

be substantial. Considering that oil sands may demand 1.2 mbbl/d of this blended

fuel production to comply with the LCFS—or more than 14% of the projected

blended fuels market in 2030—a biofuels supply constraint potentially could emerge.

Moreover, because the marginal cost of blending these fuels is less for conventional

gasoline suppliers (who require lower blended volumes to achieve LCFS), it is likely

that oil sands producers would be especially disadvantaged by any supply shortage

of advanced biofuels. Th is may cause them to resort to other options, such as

purchasing carbon off sets or investing in carbon capture and sequestration, in order

to comply with an LCFS in their main export market.

A federal LCFS could reduce

demand for oil sands by

one-third by 2030.

Figure U. Oil Sands Production with LCFS Compliance through 2030

Source: RiskMetrics Group, referencing CAPP Growth forecast

20072008

20092010

20112012

20182026

20282016

20222024

20142020

20132015

20172019

20212023

20252027

20292030

20062005

CAPP Growth

LCFS compliance

4000

3500

3000

2500

2000

1500

1000

500

0

1,0

00

bb

ls/d

ay


1.6 Sensitivity AnalysisTh e above conclusion rests on several important assumptions:

Canadian oil sands producers plan to retain access to the U.S. transportation

fuel market by complying with the LCFS, starting fi rst with a renewable fuel

blending strategy

Volumes of renewable fuels set forth in the RFS2 are achieved in each

renewable fuel category set forth by the EPA

Th e California LCFS is adopted at the federal level and applies across the United

States by 2020

A further 10% reduction in carbon intensity of transportation fuel is required

nationwide by 2030

We consequently test each of these assumptions in this sensitivity analysis.

Failure to Comply with LCFSIn the unlikely event that no options were available for Canadian oil sands producers

to comply with the LCFS—including no use of blended renewable fuels or other

carbon off sets through trading systems—the U.S. transportation market could

conceivably disappear for Canadian oil sands producers. If no other markets were

to materialize to make up for this loss, oil sands production could be limited to 1.8

mbbl/d by 2030, equal to an annual growth rate of only 1.9%, compared to 5.6%

under the CAPP Growth forecast. (As with each comparison to the CAPP Growth

forecast, this estimate has already incorporated the other demand-reducing measures

discussed earlier.) Th is worst-case scenario would leave oil sands producers with less

U.S. demand in 2030 than the estimated 2 mbbl/d of production estimated by CAPP

for oil sands projects already in operation and under construction.

Failure to comply with a

federal LCFS could reduce

oil sands demand below

production from projects

already in operation and

under construction.

Figure V. Oil Sands Production without LCFS Compliance


20072008

20092010

20112012

20182026

20282016

20222024

20142020

20132015

20172019

20212023

20252027

20292030

20062005

CAPP Growth

No LCFS compliance

4000

3500

3000

2500

2000

1500

1000

500

0

1,0

00

bb

ls/d

ay


Reduced Renewable Fuel AvailabilityA further consideration is whether the production targets set forth by the U.S. EPA

for RFS2 will be achieved. In its 2010 forecast, the U.S. Energy Information Agency

estimates that renewable volumes will not reach their target of 36 billion gallons of

production by 2022, due primarily to lower projected volumes of cellulosic ethanol,

which off ers the highest per volume carbon reductions for liquid transportation

fuels. Th e EIA estimates that such renewable production volumes may not approach

36 billion gallons annually until 2030 (see Figure W).

Th e EPA recently reduced its target for cellulosic ethanol below the level set under

RFS2 from 100 million gallons to just 6.5 million gallons for 2010, while maintaining

its initial targets for other advanced renewable fuels. Th e EPA is continuing to

monitor the progress of the cellulosic ethanol industry and may make further

adjustments to its annual targets. Cellulosic ethanol producers say they need more

government tax incentives and risk sharing in order to the meet EPA’s targets for

2022. Widespread adoption of LCFS would likely spur additional development

and production of advanced biofuels, though it is uncertain whether it would be a

suffi cient catalyst to make up the projected shortfall.

Th e EIA 2010 forecast also assumes that corn-based ethanol will continue to

represent a majority of renewable transportation fuels through 2022. Our analysis

assumes that such corn-based ethanol only would achieve an average 20% carbon

reduction per barrel under RFS2. Th is has important implications for our modeling

assumptions, because it suggests that a greater amount of renewable fuels would be

required under an oil sands blending strategy if corn-based ethanol was being used

instead of cellulosic ethanol that off ers a 60% carbon-intensity reduction potential.

Under these circumstances with greater reliance on corn ethanol, implementation

of a federal LCFS, with a 20% reduction in carbon intensity required by 2030, oil

sands production would fall to 2.4 mbbl/d, down from 2.6 mbbl/d. However, this

also assumes that other elements of RFS2 would be achieved as proposed by EPA,

Figure W. Advanced Renewable Fuel Projections through 2035

Source: RiskMetrics Group, referencing EIA 2010 EIO

Biofuels grow, but fall short of the 36 billion gallon RFS target in 2022, exceed it in 2035

45

40

35

30

25

20

15

10

5

02008

RFS with

adjustments under

CAA Sec.211(o)(7)

bil

lio

n g

all

on

-eq

uiv

ale

nts

2022 20352022 in

AEO2009

Legislated RFS in 2022 Renewable diesel

Biomass-to-liquids

Biodiesel

Net ethanol imports

Other feedstocks

Cellulosic ethanol

Corn ethanol

Oil sands producers have

a direct incentive to see

advanced renewable fuels

succeed.


including 16 billion gallons of cellulosic ethanol production by 2022. Th is reduced

level of production is shown in Figure X and is notably close to production levels

projected under the Operating and Construction case issued by CAPP. Th is raises the

stakes for oil sands producers intent on expanding production, particularly as it will

depend on increased renewable fuel availability to blend into their fuels. Th is gives

oil sands producers a strong business case to encourage the rapid scaling-up of low-

carbon fuels.

No Additional Carbon Reduction after 2020 under LCFSTh e reference scenario in our model assumes that the LCFS standard will be extended

after 2020, with an additional 10% reduction in carbon intensity required from 2021

to 2030. An alternate scenario holds the LCFS at the 10% reduction level set for

2020 at 468 kg CO2/bbl will be maintained through

2030 (shown in the dashed line in Figure Y). Th is

would eff ectively reduce the amount of ethanol

blending required to remain in compliance with the

LCFS through 2030. At the same time, our model

maintains the assumption that there will continue

to be modest reductions in the carbon intensity of

renewable fuels after 2022, as defi ned under RFS2,

which would further benefi t oil sands producers.

Under this alternate scenario, with the carbon

intensity reduction held constant at 10% after 2020,

the blending requirement for oil sands producers

would bottom out at 61% in 2020 (with 39% for

renewable fuels) – as depicted in Figure AA. Th en,

with the increasing carbon reduction potential of

renewable fuels through 2030, the blending ratio rises

to 67% for oil sands by 2025 (with 33% for renewable

Figure Y. LCFS Carbon Intensity Held at 2020 Level


600

500

400

300

200

100

0

20102012

20182026

20282016

20222024

20142020

2030

LCFS Carbon Reduction Scenarios to 2030

kg of CO2/bbl held at 10% reduction

kg of CO2/bbl grows to 20% reduction

Figure X. Oil Sands Production Comparisons through 2030


4000

3500

3000

2500

2000

1500

1000

500

0

20072008

20092010

20112012

20182026

20282016

20222024

20142020

20132015

20172019

20212023

20252027

20292006

2005

CAPP Growth

Federal LCFS

Lower RF availability

CAPP Ops & Constr

No Federal LCFS Compliance

2030

1,0

00

bb

ls/d

ay


fuels) and remains approximately at that ratio for the remainder of the period. Th is

has a positive eff ect on oil sands production, which would be projected to grow at

a 3.9% annual rate from 2010 to 2030, instead of the 3.4% rate under the reference

scenario outlined earlier with a 20% reduction in carbon intensity by 2030.

LCFS Applied to Selected States and RegionsOur reference scenario assumes that the California LCFS will be implemented at the

federal level and go into eff ect nationwide in 2011. However, it is quite possible that

the LCFS will be implemented only by certain states or regions. As discussed earlier,

California’s fi rst carbon intensity reductions under the LCFS for petroleum fuels will

be disclosed in 2011. Eleven other states in the Northeast and Mid-Atlantic regions

are expected to announce their own LCFS frameworks in early 2011. In combination

with California, these states account for approximately 25% of the nation’s demand

for liquid petroleum fuels.

If these are the only states that implement an LCFS, with the carbon reduction

requirement rising to 20% by 2030, the eff ect on the CAPP Growth forecast (without

any federal LCFS regulations) would be to reduce the annual growth rate to 4.5% from

5.6% and reduce oil sands production from 3.8 mbbl/d to 3.2 mbbl/d by 2030. Figure

BB also makes projections of the eff ects on oil sands production if 50% or 75% of the

U.S. transportation fuel market were subject to a California-type LCFS. A 50% market

share for LCFS would reduce the CAPP Growth forecast by 22%, to 2.94 mbbl/d by

2030, and reduce the industry’s projected annual growth rate to 4.15%. At 75%, the

annual growth rate would be further reduced to 3.8%.

As a practical matter, the eff ects of LCFS may have much greater regional distinctions

than these averages suggest. For example, California and the Northeast have the

least direct access to Canadian heavy crude oil at present. In addition, the Northeast

states are considering a phase-in of home heating oil into the mix of fuels subject

Figure Z. Oil Sands Production under 2020 LCFS Carbon Intensity


4000

3500

3000

2500

2000

1500

1000

500

0

20072008

20092010

20112012

20182026

20282016

20222024

20142020

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20212023

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20292006

2005

CAPP Growth

Constant LCFS 2020–2030

LCFS Compliance

2030

1,0

00

bb

ls/d

ay


to LCFS, which might further limit oil sands producers’ penetration of this market.

At least 16 other U.S. states import Canadian heavy crude directly, with the greatest

concentration in the Midwest. In Montana, 93% of the oil consumed in the state

comes from Canada. In Minnesota, Canadian imports account for 83% of the oil

consumed, and in Illinois the proportion is 58%. Accordingly, the Midwest likely

would have the greatest impact on oil sands production of any region implementing

an LCFS standard. As noted earlier, the Midwestern Governors Association has

adopted an Energy Security and Climate Stewardship platform that includes a

commitment to create a uniform, regional low-carbon fuels policy.

While the Midwest is particularly dependent on imports of heavy crude oil from

Canada, this region is also the United States’ greatest source of biofuels. Its ethanol

producers are aggressively pursuing policies to promote their greater role in future

transportation fuels. Accordingly, an LCFS adopted in the Midwest could work

particularly well, since the region already has the infrastructure in place, including

pipelines and refi neries, to connect with Canadian oil sands. At the same time,

this connection could stimulate U.S. employment, promote investments in clean

technology and help achieve the goals set forth under RFS2.

According to a 2009 analysis by Bio Economic Research Associates, a private research

and advisory fi rm:

Direct U.S. job creation from advanced biofuels production could reach 29,000

by 2012, rising to 94,000 by 2016 and 190,000 by 2022.

Total job creation, accounting for economic multiplier eff ects, could reach

123,000 in 2012, 383,000 in 2016, and 807,000 by 2022.

Figure AA. Projected Blend of Oil Sand and Renewable Fuels

under 2020 LCFS

Source: RiskMetrics Group, comparing eff ects of 10% (brown line) and 20% reductions in carbon intensity

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

20102011

20122018

20262028

20162022

20242014

20202013

20152017

20192021

20232025

20272029

2030

LCFS Reduction Scenarios: Blending Requirement

Oil sands producers already

have strong ties to the US

Midwest, the greatest source

of biofuels supply.


Investments in advanced biofuels processing plants alone could reach

$3.2 billion in 2012, rising to $8.5 billion in 2016, and $12.2 billion by 2022.

Cumulative investment in new processing facilities between 2009 and 2022

would total more than $95 billion.

In addition, direct economic output from the advanced biofuels industry,

including capital investment, research and development, technology royalties,

processing operations, feedstock production and biofuels distribution, could rise

to $5.5 billion in 2012, reaching $17.4 billion in 2016, and $37 billion by 2022.42

1.7 Modeling ConclusionsOur modeling results suggest that, under a business-as-usual scenario, Canadian

oil sands producers may be able to achieve the Growth forecast set forth by the

Canadian Association of Petroleum Producers (CAPP) of 3.7 mbbl/d by 2030. Th is

is mainly dependent on future U.S. demand for liquid petroleum fuels, and assumes

that no other production- or demand-limiting factors come into play. Th e eff ects

of U.S. legislation to stimulate production of more fuel-effi cient, hybrid and electric

vehicles are expected to have only a modest eff ect on oil sands production forecasts,

possibly eliminating the need for 0.3 mbbl/d of production by 2030.

Adoption of Low Carbon Fuel Standards (LCFS), on the other hand, could have a

much more signifi cant impact. Our model shows that compliance with a U.S. federal

standard that seeks a 20% reduction in the carbon intensity of liquid transportation

fuels between 2010 and 2030 could eliminate 1.2 mbbl/d of oil sands production

by 2030—a 33% reduction relative to the CAPP Growth forecast. Th is reference

42. “U.S. Economic Impact of Advanced Biofuels Production: Perspectives to 2030,” Bio Economic Research

Associates, Feb., 2009.

Figure BB. Projected Oil Sands Production under

Regional LCFS through 2030

Source: RiskMetrics Group, referencing CAPP Growth and Operating & Construction forecasts

4000

3500

3000

2500

2000

1500

1000

500

0

20072008

20092010

20112012

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20142020

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CAPP Growth

25% under LCFS

50% under LCFS

75% under LCFS

Federal LCFS

CAPP Ops & Constr


1,0

00

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ls/d

ay


scenario also assumes that advanced renewable fuels will be available in suffi cient

quantities to provide for blending with oil sands crude, and that the cost of bringing

this blended fuel to market will not put oil sands producers at a distinct disadvantage

relative to conventional petroleum producers.

Th ese are critical assumptions that may not pan out and which could result in

signifi cant additional downward pressure on oil sands production. Low carbon-

intensity, renewable fuels may not be available in suffi cient quantities to meet the

fuel-blending requirements that RFS2 has set for 2022. Th is gives oil sands producers

a direct incentive to support and invest in renewable fuels production to help meet

these goals.

If the renewable fuel blends fall short of these goals, oil sands producers would

have to resort to other options in order to comply with the LCFS. Th ese include the

purchase of LCFS carbon allowances to off set the higher carbon content of oil sands

crude and investment in carbon capture and sequestration (CCS) technology to store

emissions underground. We estimate that a $100 per ton price on transportation

sector carbon dioxide off sets would eff ectively increase the price of oil sands

production by about $11.40 per barrel relative to the price of conventional crude on

a fi eld-to-wheels basis, placing oil sands producers at a further cost disadvantage in

their production costs. Any further carbon levies at the consumption level should

aff ect oil sands and conventional oil producers equally—but would disadvantage

both relative to alternative lower-carbon and no-carbon fuels.

Th e pool of transportation sector off sets available to oil sands producers will

determine what role this option might play in coming years. Th e California LCFS,

for example, restricts the use of carbon off sets to parties within the transportation

sector, where GHG reductions are generally more expensive than in other markets.

Such a limited pool of off sets, and the resulting higher allowance prices, could

especially disadvantage oil sands producers. In addition, successful deployment of

CCS technology remains uncertain and is at least 10 to 15 years away from wide scale

commercial application. Moreover, the amount of emissions likely to be sequestered

is still likely to leave Alberta’s oil sands producers as major growing carbon emitters,

complicating Canada’s federal GHG reduction goals.

Another consideration is whether added costs of oil sands production through

levies on carbon emissions and deployment of CCS technology could further raise

production prices to the point that oil sands can’t compete on the market. At

present, global oil prices need to be sustained above $65 per barrel, and possibly

range above $95 per barrel, to justify investments in oil sands production. Production

costs may go higher still as more consideration is given to water constraints, tailings

pond management and other environmental issues (which are discussed later in this

report). Th erefore, oil sands producers face particular challenges in passing these

added costs onto consumers, especially given that the global oil market through 2030

is likely to be driven by conventional oil producers that produce most of the supply

with far fewer constraints.

Th ese conventional producers, in combination with global demand, will continue

to set the market price for oil. Oil sands producers will not be in a position to shape

these market trends. It follows that oil sands producers may not be able to pass all of

their added carbon production costs onto consumers. Accordingly, the global price

Pricing carbon and limiting

emissions will increase the

delivery price of oil sands.


of conventional oil must be able to sustain the costs of synthetic crude oil sands

production and related carbon mitigation strategies.

At the same time, if global oil prices spike too high, perhaps in a range of $120 to

$150 per barrel, the conservation-inducing eff ects and stimulus for alternative energy

production may crimp oil sands production.43 At that point, other demand-reducing

and alternative-supply measures may come into play. Accordingly, in the foreseeable

future, oil sands producers must operate within a narrow fi nancial window where oil

prices must maintain relatively stable and moderate pricing levels—something that

has rarely happened in the increasingly volatile global oil market.

Perhaps the biggest uncertainty of all is whether Canadian oil sands producers

will fi nd markets for their products outside of the United States, which presently

consumes more than two-thirds of all Canadian oil production. Asia remains a vast,

growing and virtually untapped market for oil sands producers. However, reaching

that market would require major investments in new pipelines, refi neries and

shipping capacity, and faces legal roadblocks from First Nation communities opposed

to such expansion. Other oil producers from the Middle East and Russia have much

more ready access to the Asian market.

Finally, oil sands producers must confront the reality that they produce one of the

world’s most carbon-intensive fuels. As described earlier in this chapter, eff orts to

reduce the carbon intensity of U.S. transportation fuels may force oil sands producers

to look for new markets as they seek to expand production. But as carbon emissions

constraints become more of a global priority, these other markets also may off er

diminishing returns. Even within Canada, oil sands producers face the specter of

becoming one of the largest and fastest growing sources of carbon dioxide emissions

at a time when Canada is committed to major emissions reductions.

For investors, this raises a series of questions to address with oil sands producers:

To what extent do they expect to continue to rely on the United States as their

dominant export market?

How do they intend to address the emerging challenge posed by Low Carbon

Fuel Standards and other carbon-restricting regimes?

Will they be able to secure suffi cient supplies of aff ordably priced advanced

biofuels to blend with their products?

What investments will they make in renewable fuels, carbon capture and

sequestration and other carbon off sets to reduce their carbon footprint?

Finally, and most importantly, can they assure investors that their products will

remain economically viable and sustainable as they address not only the carbon

challenge, but also the water, reclamation, Indigenous rights and other issues

addressed in this report?

43. “Growth in the Canadian Oil Sands: Finding a New Balance,” Cambridge Energy Research Associates

(CERA), Mar. 2009.

Low Carbon Fuel Standards

and lack of access to other

export markets could

greatly curtail demand for

oil sands.


2. Water and Oil Sands Production Sustained demand for carbon-intensive transportation fuels is not the only risk

factor aff ecting future oil sands development. Water also poses a potentially critical

constraint. Oil sands production is highly water-intensive. For each barrel of synthetic

crude produced through oil sands mining, up to four barrels of freshwater are

consumed. For in situ projects, less than a barrel of water is consumed for each barrel

of SCO produced.

Existing and planned oil sands mines may divert more than 500 million cubic

meters of water annually from the Athabasca River in Alberta.44 At times of low

fl ow, especially in the winter, this diversion could threaten fi sh habitat. Our analysis

indicates that oil sands producers dependent on securing fresh water supplies may

encounter shortages by 2014 unless they make additional investments in water

storage and treatment facilities.

In-situ oil sands producers also face new rules on the measurement, use and recycling

of water at their facilities. In particular, these operators are being encouraged to use

saline aquifers rather than fresh groundwater. Th e long-term availability of these

aquifers and the impacts of large scale extraction on regional hydrogeology remain

uncertain.

While Alberta’s oil sands resources lie in the region the world’s third largest

watershed, known as the Mackenzie River basin, the province has a relatively dry

climate—which could become even more so due to climate change. Th e Athabasca

Glacier in the Columbia Ice Field, which feeds the Athabasca River, has already

receded 1.5 kilometers and lost half of its volume. According to Dr. David Schindler,

an ecology and water expert at the University of Alberta, climate impacts could

reduce the Athabasca River’s fl ow by 50% in winter months by mid-century.45 Th is

could be a key constraint in maintaining uninterrupted production from oil sands

operations.

2.1 Water Primer Currently, commercially employed oil sands technologies are exclusively water-

based. Water is a critical element of oil sands operations, as it is part of all aspects of

production—from extraction, to separation, to upgrading. Water utilization diff ers in

mining and in-situ recovery processes.

In mining extraction, the crushed oil sand is mixed with water and transported

via pipeline to separation facilities where it undergoes a separation process. Th is

hydrotransportation serves as a conditioning process facilitating the separation of

bitumen from sand. In the primary separation, the bitumen froth is removed and

further transported via pipeline to upgrading facilities. Th e sand, along with excess

water mixed with clay, residual bitumen and other toxic compounds are deposited in

large tailing ponds. In these ponds, fi ne clay suspended in the water settles out over

44. “Lines in the Sands: Oil Sands Sector Benchmarking,” Northwest & Ethical Investments, published by

Ceres, Nov. 2009.

45. David Schindler and Vic Adamowicz, “Running Out of Steam? Oil Sands Development and Water Use

in the Athabasca River-Watershed: Science and Market-Based Solutions,” University of Toronto (Munk

Centre), May 2007.

Oil sands mining requires

four barrels of freshwater

for every barrel of oil

produced.


a period that typically takes several decades, allowing water recovery and eventual

soil reclamation. On average, two thirds of the water used is recycled back into the

extraction process, but fresh, so-called make-up water is continuously required.

All in-situ technologies, including the most commonly used steam-assisted gravity

drainage (SAGD), entail water withdrawal primarily from underground aquifers,

injection of steam back underground, and pumping of the bitumen and water

mixture to the surface. With the bitumen froth, produced water is also pumped

above ground, which allows for signifi cant water recycling. However, similar to

mining, some make-up water is also needed to meet the steam requirements.

Th e product of both mine and in-situ extraction— bitumen froth—is piped to

upgrading facilities where it undergoes further separation from residual water and

clay. Water use in upgrading includes hydrotreating and cooling, while solvents are

used to synthesize the heavy bitumen into synthetic crude oil, suitable as refi ning

feedstock.

2.2 Catalysts for Sustainable Water Management Large-volume water requirements for oil sands mining and in-situ extraction place

a particular need on responsible water management, especially for water recycling

and associated treatment. Seasonal changes in water availability make it especially

important that mining producers invest in water collection and storage. In-situ

producers—while facing fewer water requirements overall—also need water for

steam generation that results in higher costs of water treatment from various sources,

including produced/recycled freshwater and underground saline aquifers. Water

management and ultimate reclamation of tailing ponds are contentious issues with

highly uncertain costs down the road.

While there is no charge for industrial water use in Alberta, permits for fresh water

withdrawal are in place that benefi t the oldest oil sand producers. Th ese “legacy”

oil sands miners have generous licenses and are at little risk of exceeding their

allowances. It is possible that their withdrawals during low fl ow periods could leave

new producers without adequate water supplies. As a result, most new mining

projects have built-in water storage to ensure water supply during low-fl ow periods.

Despite attempts by the Albertan government to address this issue, no agreement

has been reached with legacy miners on how they might share their favored water

allowances with new producers. Th e government has put the industry on notice that

a collective answer must be found on water management as oil sands development

moves forward. Th is could include banning water withdrawals in critical fl ow periods

for some river systems, such as the Muskeg River, which drains into the Athabasca

River—possibly suspending the operations of oil sands producers lacking suffi cient

water storage.

Mining producers also face growing water management challenges under Directive 74

of Alberta’s Energy Resources and Conservation Board. Published in February 2009,

this regulation requires oil sands miners to disclose specifi c plans and timelines to

speed up the remediation process of existing ponds and progressively treat tailings.

(See Section 3.7 for a more detailed description of Directive 74.) At present, only one

of eight mining operators is in compliance with this aspect of the directive.

In-situ operators use less

water but still face resource

and regulatory constraints.


In-situ operators are not subject to Directive 74, but also face new regulations

that seek higher recycling rates of water that goes through their operations. Th ese

operators must achieve a recycling rate of 90% for facilities that utilize freshwater and

75% for operations using saline water. At present, eight out of 11 mining operators

are in compliance with these regulations. Not all sites have access to saline water,

however. Two of the three in-situ producers that are not yet in compliance are

companies trying to meet the 90% recycling target for utilizing mainly freshwater

sources. Existing projects have until 2014 to comply with this regulation.

Improvements in tailings management (discussed in the next chapter) may

increase the water recycling rate and make oil sands producers less reliant on water

withdrawals from the Athabasca River watershed and underground aquifers.

2.3 Water Use In order to analyze the water availability and tailings issues more closely, we have

considered industry-wide data as well as project- and company-specifi c information.

We have reviewed publicly available environmental reports and opinions46 in order

46. Th e list of literature includes, but is not limited to, the following publications:

“Th e Sustainable Management of Ground Water in Canada,” Council of Canadian Academies, May 2009.

“Clearing the Air on Oil Sands Myths,” Th e Pembina Institute, 2009.

“Tar Sands: Dirty Oil and the Future of a Continent,” Andrew Nikiforuk, Mar. 2009.

“Growth in the Canadian Oil Sands,” CERA, 2009.

Figure CC. Average industry-wide water use (bbls) per one barrel of synthetic crude oil (boe)

Water use (bbls) per one barrel of synthetic crude oil (boe)

Water (bbls)

Gross Water Intake Net Water Intake Recycled Water Recycling Rates

Mining

Low 10Low 2 8 80%

High 4.5 5.5 55%

High14 Low 2 12 86%

12 High 4.5 9.5 68%

Average 12 3.25 8.75 72%

In-situ

Low 3Low 0.2 2.8 93%

High 0.9 2.1 70%

High7 Low 0.2 6.8 97%

12 High 0.9 6.1 87%

Average 5 0.55 4.45 87%

Upgrading

Low 3Low 0.3 2.7 90%

High 0.7 2.3 77%

High5 Low 0.3 4.7 94%

12 High 0.7 4.3 86%

Average 4 0.5 3.5 87%

Source: RMG modeling based on reviewed literature


to assess the average barrels (bbl) of water requirements per barrel of oil equivalent

(boe) of oil production. Consequently, we retained the widest ranges available within:

Mining

– gross water requirement: 10 bbl to 14 bbl

– net water requirement (gross less recycled): 2 bbl to 4.5 bbl

In-situ

– gross water requirement: 3 bbl to 7 bbl

– net water requirement (gross less recycled): 0.2 bbl to 0.9 bbl

Upgrading

– 1.8 bbl water (Shell, Scotford, 2005)

Figure CC maps out the most likely average water consumption and recycling rates.

In addition to providing average levels, our analysis considers two fresh water use

scenarios for mining projects:

High, 4.5:1 ratio

Low, 2:1 ratio

As these results show, mining is a much more water-intensive operation than in-situ

production:

on a net water intake basis, approximately six times more (3.25 bbls/0.55 bbls)

fresh water is needed to mine bitumen compared to in-situ recovery

while the effi ciency of bitumen recovery through mining is at 90%, and only

between 20–35%47 for in-situ projects, the gross water requirement of mined

bitumen is on average 2.5 times higher (12 bbls/5 bbls)

water recycling rates range between 55-80% for mining, compared to 70-93%

for in-situ projects

Figure DD considers the cumulative industry water use. We have compiled fresh

(net) water needs associated with mining and in-situ production based on the 2009-

2025 forecast by the Canadian Association of Petroleum Producers.48 As discussed

in Chapter 1, this forecast includes two scenarios: a Growth scenario that assumes

steady increases in production for the industry, and an “Operating & in Construction”

scenario that assumes production only from those projects that are currently

operating or under construction. Th e chart shows the daily estimated net (make up)

water use for mining and in-situ, and the cumulative amount for both. Th e units are

expressed in barrels per day and compared against the oil production estimates in

order to provide a visual sense of scale.

47. Len Flint, “Bitumen Recovery Technology, A Review of Long Term R&D Opportunities,” Lenef Consulting

Limited, Jan. 2005.

48. “2009–2025 Canadian Crude Oil Forecast and Market Outlook,” Canadian Association of Petroleum

Producers (CAPP), Jun. 5, 2009.


2.4 Water AvailabilityHaving determined the cumulative fresh water requirement, the question becomes:

How will Alberta’s watershed support projected rates of increase in oil sands

production?

Oil sands producers draw water from the following sources:

Mining: As discussed, these producers generally use fresh surface water. Th ere are

three key water bodies that correspond to the three main extraction fi elds: the

Athabasca River, the Peace River and Cold Lake. Th e Athabasca River, which

fl ows through Fort McMurray, is the largest reserve and the only one suitable

for surface mining. It represents about 20% of total reserves. Mining and

upgrading draws water exclusively from the Athabasca River and Mildred Lake.

In-situ: Th ese producers mostly use underground water, both from fresh and

saline aquifers. According to CAPP, more saline water than fresh water has been

withdrawn for in-situ extraction since 2007.49 Underground water availability

is highly localized, with highly saline water less effi cient in extracting bitumen

from oil sands. Companies need to fi le water permits only for water with

salinity that is below a regulated threshold level. Permits for fresh underground

water withdrawal are granted on a project by project basis in connection with

an environmental impact assessment (EIA) that includes consideration of

regional cumulative impacts on aquifers from all other users, including adjacent

oil sands projects. In-situ development, including water permitting, falls under

49. “Water use in Canada’s oil sands,” Canadian Association of Petroleum Producers (CAPP), Aug. 2009.

Figure DD. Cumulative Industry Net Water Use and Oil Production

Source: RMG modeling based on water utilization metrics and CAPP oil sands production forecast

7

6

5

4

3

2

1

0

20072009

20112013

20152017

20192021

20232025

2005

Mb

bl/

d

Net Water – Growth

Water Mining – Growth

Net Water – Operating & In Construction

Water Mining – Operating & In Construction

Oil Production – Growth scenario

Oil Production – Operating & In Construction scenario

Water In-Situ – Growth

Water In-siutu – Operating & In Construction

Net water demand for oil

sands could triple over 20

years.


a diff erent set of regulations and is treated in the same ways as lease contracts

for conventional oil producers.

Given the higher water intensity and lower recycling rates of the mining process—

averaging 72% vs. 87% for in-situ—mining operations have the biggest water impacts

at present. Going forward, however, in-situ projects may have a larger ecosystem

impact and account for a growing share of water withdrawals, given that roughly

80% of the total oil sands deposit is available for recovery through in-situ recovery

methods.50

Calculating the water availability constraints for in-situ operators is constrained

by a lack of data on underground water availability data. Th e Pembina Institute,

a respected environmental think-tank based in Calgary, Alberta, has conducted

a comparative environmental assessment of in-situ projects that will address

this issue.51 Of note is that the steam-oil ratio (SOR) for new oil sands projects is

increasing, which means higher volumes of water are required for steam generation

in bitumen production. For steam assisted gravity drainage (SAGD) projects, the

SORs of earlier projects were around 2:1, meaning two units of steam were required

for production of one unit of oil. Some newer projects have SORs as high as 7:1 and

8:1 that imply increased water consumption and power generation needs.

According to the Pembina Institute, the growth of fresh water utilization for in-situ

projects is three times higher than the Albertan government forecast of 110 million

cubic feet annually. Th e think tank estimates that even though saline water recycling is

now favored under regulations, the industry may still source as much as half of its water

needs from fresh water sources as late as 2015. In-situ producers currently account for

7% of total fresh water withdrawals from the Athabasca River, and at peak production

it is forecast to withdraw as much water as the mining industry does currently.

In addition, the main by-product of in-situ processes that utilize saline water is

accumulated salt. It is estimated that the average SAGD producer annually generates

33 million pounds of salts and water-solvent carcinogens that are destined for

landfi lls.52 Salt disposal may become a signifi cant waste disposal issue for producers

that could trigger additional environmental management expenses.

Oil Sands Mining and the Athabasca RiverAs discussed, a potential production constraint for oil sands mining projects is the

volume of water withdrawals available from the Athabasca River. Th e Athabasca

River and its tributaries are the exclusive source of water for oil sands operations in

the Ft. McMurray region. Oil sands mining operators rely on water licenses granted

by Alberta’s Energy Resources Conservation Board (ERCB) that specify the maximum

level of water that can be drawn from the Athabasca River.

Average total fl ows from the Athabasca River are roughly 500 cubic meters per

second (m3/s). Th is compares with 5.12 m3/s of average withdrawals by oil sands

producers in 2008—or roughly 1% of the total yearly fl ow. However, fl ow rates in the

50. Council of Canadian Academies, 2009.

51. Simon Dyer, Jeremy Moorhouse, and Marc Huot, “Drilling Deeper: Th e In Situ Oil Sands Report Card,” Th e

Pembina Institute, Mar., 2010.

52. Andrew Nikiforuk, “Tar Sands: Dirty Oil and the Future of a Continent,” Mar. 2009, p.67–69

In-situ operators with high

steam-oil ratios need more

water and natural gas to

produce synthetic crude.


Athabasca River vary greatly by season, ranging from average high fl ow rates of 859

m3/s in the summer to low fl ows of 177 m3/s in the winter.53

Th e provincial agency Alberta Environment (AENV) and the federal agency Fisheries

and Oceans Canada (DFO) regulate the maximum amount of water withdrawals to

maintain ecosystems dependent on river fl ows, especially in low-fl ow periods. At this

time, withdrawal rates by all users, including oil sands producers, may not exceed

5.2% of the median river fl ow.54 Th is restricted period of water withdrawal for oil

sands operators extends from October 29 to April 22, with withdrawal limits set in

a range of 8-15 m3/s.55 In Figure EE, we compare the oil sands miners’ water needs

to the lower (8 m3/s) and upper (15 m3/s) regulatory limits. Th is projection assumes

53. Jennifer Grant and Simon Oxes, “Clearing the Air on Oil Sands Myths,” Th e Pembina Institute, Jun. 2009.

54. “Growth in the Canadian Oil Sands,” IHS & CERA, 2009.

55. “Water use in Canada’s oil sands,” Canadian Association of Petroleum Producers (CAPP), Aug. 2009.

Figure EE. Comparison of Cumulative Industry Projected Water Usage

with Water Availability in the Athabasca River

16

14

12

10

8

6

4

2

0

20072009

20112013

20152017

20192021

20232025

2005

Cu

bic

me

ters

pe

r se

co

nd

Growth – Low Water Needs Flow

Growth – High Water Needs Flow

Lower limit of winter availability

Upper limit of winter availability

Operating & In Construction – Low Water Needs Flow

Operating & In Construction – High Water Needs Flow

Mining Water Needs Flow (cubic meters/second)

Water Use under Production Forecast Scenarios 2008 2009 2014 2015 2020 2025

Growth

Low water use ratio [2:1] 2.32 2.69 3.88 4.15 4.98 5.76

High ratio [4.5:1] 5.21 6.06 8.73 9.33 11.22 12.97

Average ratio [3.25:1] 3.76 4.37 6.31 6.74 8.10 9.37

Operating

Low ratio [2:1] 2.32 2.69 3.72 3.76 3.82 3.82

High ratio [4.5:1] 5.21 6.06 8.38 8.46 8.60 8.60

Average ratio [3.25:1] 3.76 4.37 6.05 6.11 6.21 6.21

Water withdrawals from the

Athabasca River are already

restricted in winter months

to protect fi sh habitat.


that average water availability in the Athabasca River will remain unchanged,

although summer fl ows in the Athabasca have declined 29% since 1970 and some

studies (as noted earlier) project that winter fl ows could be cut by as much as 50%

by mid-century.56 Th e fi gure shows that in both the Growth and the Operating &

Construction scenarios, when considering the high 4.5:1 water to oil ratio, water

withdrawals are moving above the 8 m3/s threshold by 2014; this marks the lower

end of the regulated limit of 8-15 m3/s. When considering the average water

consumption ratio of 3.25:1 water-to-oil ratio, only the Growth scenario could enter a

danger zone of regulatory limitations beginning in 2020.

2.5 Conclusions on Water ManagementOur analysis fi nds that under the high water use rate of 4.5:1, production constraints

for oil sands miners could emerge as early as 2014, under both the Growth and

Operating scenarios, with producers encountering diffi culties in securing water from

the Athabasca River in the winter months. Accordingly, by 2014 oil sands producers

facing freshwater shortages will need to build water storage facilities to meet

continuous production requirements. Producers that achieve a water consumption

rate of 2 bbl/boe should be in a better position to maintain their withdrawals under

both the Operating scenarios, although this is partly dependent on whether the

collective demands placed by producers on the watershed demonstrate a move

toward greater effi ciency and recycling rates. As oil sands production rises, pressure

will mount on all oil sands producers to achieve average water withdrawal ratios of at

least below 4:1.

Mining producers presently require four barrels of water on average to produce a

barrel of synthetic crude, placing them at much higher risk than in-situ producers,

with a ratio below 1:1. Miners lacking generous water allowances granted to Alberta’s

original oil sands producers need to focus on expanded storage ponds and recycling

eff orts to address regulatory constraints that could emerge as early as 2014. Water

availability may emerge as a key operational constraint for other oil sands producers

by 2020.

In-situ producers face higher production costs associated with increased water

recycling rates. Th ese producers are much more dependent on tapping underground

saline aquifers to liberate bitumen for oil production. Th is raises in-situ producers’

water treatment costs for saline water that is not recycled and must be treated.

For in-situ developers, water treatment costs are potentially as high as 5% of total

operating costs (see Figure FF).57 Operating costs are therefore likely to increase as

companies are increasingly forced to use saline water and therefore undergo more

expensive water treatment processes. (For further discussion of water management

of mining and SAGD projects, see the following section, 3.9 Increased Salt Budgets.)

According to a recent industry analysis, the water treatment costs of mining and

in-situ projects are roughly comparable, with SAGD producers providing a slight

advantage over mining producers (see Figure FF).

56. Peggy Holroyd and Terra Sienieritsch, “Water that Binds Us,” Th e Pembina Institute, 2009, p. 10.


Limited, Jan. 2005.

Oil sands mining operators

with the highest freshwater

requirements could face

supply disruptions as early

as 2014.


Water is a key new consideration in any industrial activity in the Alberta oil sands

region. Oil sands must compete with agricultural and municipal uses of water for

the generous allowances currently provided from the Mackenzie River watershed.

Oil sands producers may lose their competitive advantage as more value is placed

on these competing demands for water, and as overall availability of water in the

province continues to decline.

As outlined in the next chapter, the management of water as it relates to tailings

disposal is a far more contentious issue for oil sands operators due to the scale of

potential environmental liabilities.

Figure FF. Water Treatment Costs for SAGD and Mining Operators

(CAD $ per barrel of oil produced)

Source: OSTRM/CERI

Climate change could

increase competition for

water in Alberta.


3. Land and Oil Sands Development

3.1 Overview of Land RisksAlberta’s oil sands are located in Canada’s vast

boreal forest. Impacts from mining and in-situ

operations are transforming this landscape and

turning one of the world’s largest carbon sinks

into a fast-growing source of carbon dioxide

emissions. Mining operations, in particular, scar

the landscape and require large-scale investments

in soil remediation and management of toxic

petroleum waste in tailing ponds. Restoring this

ecosystem is one of the industry’s biggest long-

term challenges, as the process of reclaiming the

landscape and restoring water quality will take

decades.

Canada’s oil sands industry produces 3.1 million barrels (597,000 tons) of tailings

per day — a mixture of water, sand, clay, residual bitumen, organic contaminants

(naphthenic acids, ammonia, phenolic compounds), salt and trace metals that are

waste byproducts of the extraction processes.58 Tailings accumulation is expected

to grow along with oil sands production to anywhere between 4.7 and 12.9 million

barrels of tailings per day. To date, none of the tailings ponds have been reclaimed

and they remain one of the world’s largest environmental contaminations.59 Tailing

ponds substantially alter the ecosystem by contaminating soil and water sources,

present health problems in local communities, and pose the risk of a catastrophic

breach.

As discussed in the previous water chapter, Alberta’s Energy Resources Conservation

Board (ERCB) is tightening oil sands water management under Directive 74. Th is

directive requires oil sands mining operators to remediate existing tailings ponds

within fi ve to eight years after disposal has been completed and advance the rate at

which tailings in other ponds are treated. Because fi ne tailings (FT) take as long as

40 years to settle, and currently used technology is unable to expedite this process,

companies may be forced to use alternative methods such as bioremediation to meet

the expedited schedule set by the ERCB.

In this chapter, we discuss our tailings metrics, provide estimates of tailings

production and footprint on land, examine the water/soil contamination issues and

consequent health impacts in local communities, and estimate potential contingent

liabilities for producers. We also review the regulatory catalysts to speed up tailings

remediation, such as Directive 74, and evaluate the potential fi nancial impacts on

producers.

58. Based on 4.35 bbls of tailings per barrel of oil sands-derived crude oil. Th e derivation of this metric is

presented in the consecutive discussion on land risks.

59. Jennifer Grant, Simon Dyer and Dan Woynillowicz, “Oil Sands Reclamation: Fact or Fiction?,” Pembina

Institute, Mar. 2008.

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Canada’s oil sands lie under

a vast boreal forest.


Together with the forensic accounting team of RiskMetrics (CFRA), we have

quantifi ed the potential increase in asset retirement obligations (ARO) to be

included on the balance sheet, along with raising ongoing operating costs on

the income statement that companies may incur in complying with Directive

74.60 Bioremediation costs would have the most impact on Suncor (SU) in terms

of operating expense. If bioremediation were used to treat new daily tailings

production, our analysis indicates SU’s annual net income could be reduced by 26-

104% relative to 2009 income projections. (Th is estimate does not refl ect SU’s 2009

merger with Petro-Canada or its plans to use a new proprietary method of treating

tailings to reduce this cost.) Meanwhile, Canadian Oil Sands Trust (COST) could see

a 10-26% rise in its debt to capitalization ratio, and Imperial Oil (IMO) could see a

6-17% increase in its debt ratio, in order to cover the added costs of bioremediation

for treatment of existing tailings in oil sands mining projects.

3.2 Tailings Primer Tailings are essentially mining waste. To date, current extraction methods—mining

and in situ—are both based on water-assisted production of bitumen, whereby

warm water (mining) or steam (in situ) is used to separate bitumen from sand. Th e

by-product of this process for mining operations is substantial amounts of liquid

petroleum-based slurry that is deposited into tailings ponds. In the case of in-situ

operations, produced waste liquids are re-injected into the ground, which raises

concerns about possible contamination of underground aquifers.61 However, the land

impact of mining operations is far greater than that of in-situ operations due to the

larger tailings component, and is hence the greater focus of our examination.

Oil sands mining involves the cutting of trees and draining of wetlands, the removal

and storage of overburden—the top layer of soil, muskeg and vegetation of up to 75

meters—followed by the excavation and crushing of the oil sand ore. Th is substance

is then mixed with warm water and shipped in pipelines to processing facilities,

where bitumen froth is separated from the sand,

water and clay. Th e sand separates fast in the

primary recovery process and can be further

used to construct dikes for the tailing ponds. An

average 72% of the used water is recycled back

into the production process. Th e residual slurry of

water, clays and the remaining bitumen along with

unused sand is discarded into the tailing ponds.

Th e sand settles quickly at the bottom of the

pond, but the liquid waste, called tailings, is non-

recyclable due to the impermeable content of clay

and silt. Residual bitumen is another component

of tailings and due to lower density compared to

water, it fl oats on the surface of the tailing ponds.

In a matter of three to fi ve years, between 30–40%

of such tailings settle at the bottom of the tailing

60. Yulia Reuter, Dana Sasarean and Julie Hilt Hannink, “Oil Sands Tailings Pond Remediation Costs

Understated,” RiskMetrics Group, Dec. 22, 2009.

61. Simon Dyer, Jeremy Moorhouse, and Mare Huot, “Drilling Deeper: Th e In Situ Oil Sands Report Card,”

Th e Pembina Institute, Mar. 2010.

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Toxic tailings ponds now

cover an area the size of

Washington, DC.


ponds into what is known as mature fi ne tailings (MFT)—a deposition of clay and

water of a sludge consistency. Th e remaining tailings, called fi ne tailings (FT), are fi ne

suspensions of clays that take decades to settle.

Th e in-situ oil sand extraction involves steam injection into underground deposits

and the recovery of bitumen froth. It is pumped to the surface accompanied by

produced water, while the “washed” sand remains underground along with the

associated liquid waste.

Given that oil sands mining operations generate, on average, 17.5 barrels of tailings

per one barrel of oil (boe) produced, the complexities relating to tailings treatment

pose enormous medium- to long-term environmental challenges because of the

extensive impacts on land and water.

3.3 Tailings Production As a general rule, about 1.7 tons of oil sands ore (or 4.28 bbls) are processed to obtain

1 boe.62 Based on average composition of the ore and the previously presented water

model (see Figure CC), we have compiled a resource input/output equation for oil

sands mining.

Th is equation presents a ratio so that one boe results in an average tailings

production of 17.47 bbl, of which 4.37 bbl are tailings sand, and 4.35 bbl are liquid

tailings that ultimately need to be remediated.

An important output component of our model is liquid tailings (4.35 bbls of tailings

per one boe of oil), which is the mining waste that persists in tailings ponds after

sand tailings settle and water is recycled. Liquid tailings are composed of mature fi ne

tailings (MFT) and fi ne tailings (FT), and are broken down as shown in Figure HH.

MFT (1.52 bbls on average per one boe of oil) have a tendency to settle to a semi-

solid state, and are less of a remediation problem than fi ne tailings. FT (2.83 bbls/oil

boe) represents the biggest remediation challenge for producers.

62. “Th e Sustainable Management of Ground Water in Canada,” Council of Canadian Academies, May 2009.

Figure GG. Average Barrel Input/Output in Production of 1 Boe

Average Barrel Input/Output in Production of 1 Boe

INPUT OUTPUT

Barrels of Ore

Barrels of Recycled water *

Barrels of Net (Make-up) Water

Total Barrel Input

Barrels Recyclable Water

Barrels of Liquid Tailings***

Barrels of Tailings Sand **

Total Tailings

Total Barrel Output

4.28 8.75 3.25 16.28 8.75 4.35 4.37 8.72 17.47

*Assuming average recycling rate of 72%

** A factor of 1.4 refl ects increase of the volume of sand after bitumen separation process, as the higher density feedstock is converted into lower desities, higher

volume tailings sand

*** Both fi ne tailings (FT) and mature fi ne tailings (MFT)

Source: RMG modeling based on publicly available environmental information and conversations with industry experts

Oil sands mining produces

17.5 barrels of tailings for

each barrel of oil produced.


Given the above-calculated tailings production per boe, we have estimated that the

industry’s tailings production from oil sands mining projects could reach 1.6 million

bbl/d by 2025, based on CAPP’s production forecast (Growth scenario).63

63. “2009–2025 Canadian Crude Oil Forecast and Market Outlook,” Canadian Association of Petroleum

Producers (CAPP), Jun. 5, 2009.

Figure HH. Composition of Liquid Tailings in Production of 1 Boe

Composition of Liquid Tailings in Production of 1 Boe

INPUT OUTPUT

Net water use (bbl)

Fines and clay, residual bit and water

Mature Fine Tailings (MFT) Fine Tailings

(FT)

Total Liquid Tailings

(bbl)MFT 30%* MFT 40%* Average MFT

Low 2.00 1.10 0.93 1.24 1.08 2.01 3.10

High 4.50 1.10 1.68 2.24 1.96 3.64 5.60

Average 3.25 1.10 1.30 1.74 1.52 2.83 4.35

“*Sediment settlement ratios - 30%-40% in years to form MFT

Source: RMG, based on publicly available data: Oil Sands Myths: Clearing the Air, Pembina, 2009

Tar Sands: Dirty Oil and the Future of a Continent, Andrew Nikiforuk, March 2009

Growth in the Canadian Oil Sands, IHS & CERA, 2009

Source: RMG modeling based on publicly available environmental information and conversations with

industry experts

Figure II. Mining Industry’s Oil and Liquid Tailings Production

(million bbls/d)

Source: RMG modeling of tailings production based on estimates of CAPP’s production forecast (growth scenario)

8

7

6

5

4

3

2

1

0

20072009

20112013

20152017

20192021

20232025

2005

Mil

lio

ns

bb

ls/d

Liquid Tailings (MFT+FT)

Oil Sands Mining

Tailings production could

reach 1.6 million barrels per

day by 2025.


Th e Pembina Institute estimates that there are 5.5 billion cubic meters (24.6 billion

bbls or 4.7 bn tons) of total tailings currently impounded on Alberta’s landscape.64

Of this amount, the inventory of fl uid fi ne tailings that require long-term storage is

now 720 million cubic meters (3.2 bn bbls or 518 mm tons), according to Alberta’s

environmental regulator, ERCB.65

Given that 55% (715,000 bbls/d) of Alberta’s oil sands production came from mining

in 2008, we estimate that the industry produced 1.14 billion barrels (218 million tons)

of tailings that year (equivalent of 3.1 million barrels or 597,000 tons per day). Based

on CERA’s range of production forecast scenarios, by 2035 the industry could be

producing anywhere between 1.72 bn and 4.7 bn barrels of tailings annually, or 4.7 to

12.9 million barrels per day. On a company level, estimated liquid tailings production

at capacity could reach levels presented in Figure KK.

As the industry ramps up production, the scale and pace of tailings accumulation

may be increasingly unsustainable, and runs the risk of catastrophic environmental

failures. Th is may lead to further regulatory challenges for producers, including

potential project shutdowns.

64. Jennifer Grant, Simon Dyer and Dan Woynillowicz, “Oil Sands Reclamation: Fact or Fiction?,” Pembina

Institute, Mar. 2008.

65. “ECRB releases major directive on oil sands tailings management and enforcement criteria,” Alberta

Energy Resources Conservation Board, Feb. 3, 2009. http://alberta.ca/home/NewsFrame.cfm?ReleaseID=/

acn/200902/252143CCA5597-FAC5-D7DC-C49E896F36C6F602.html.

Sand (50.13%) / FT (32.42%) / MFT (17.45%)

Figure JJ. Breakdown of Mining Industry’s Tailings Production

(million bbls/d)

Source: RMG modeling of tailings production based on estimates of CAPP’s production forecast (growth scenario)

16

14

12

10

8

6

4

2

0

20102011

20122018

20162022

20242014

20202013

20152017

20192021

20232025

20052007

20062008

2009

Mil

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bls

/d

Tailings Sand

Fine Tailings (FT)

Mature Fine Tailings (MFT)


3.4 Footprint on LandTh e latest provincial government statistics indicate that 530 km2 of land (53,000

hectares or 35% of land approved for development) have been disturbed by oil sands

mining activity to date.66 Figure LL summarizes the land footprint of approved and

proposed mining projects.

Producers claim that on a voluntary basis 6,498 ha, or 13.6% of disturbed land has

been reclaimed. However, to date, none of the existing tailing ponds have been

offi cially certifi ed as remediated. Despite the use of chemical treatment technology

by Suncor since 1994 (see the following section on Tailings Management Options),

the company has failed to reclaim any of its tailing ponds. Suncor says it plans to

reclaim its 40-year old Pond 1 in 2010. However, the FT in this pond essentially

is being drained to alternative ponds in order to expose the MFT and allow soil

reclamation of the pond surface.

Th e only remediation certifi cate fi led with regulators was awarded to Syncrude in

March 2008 for remediation of 104 ha at the Gateway Hill project; this equals 0.2%

of land disturbed by the industry as a whole. Th e area did not include a tailing pond,

and hence the remediation eff ort involved replacing the overburden and turning

what was once a low-lying wetland into a forested upland. In principle, this does not

meet the mandated requirement to return the land to the so-called equivalent land

capability.

66. Government of Alberta, http://www.energy.gov.ab.ca/OilSands/791.asp.

Figure KK. Liquid Tailings Production at Projected Capacity

Mining production at capacity (boe/d)

Liquid Tailings Production at Capacity (bbl/d)

Syncrude¹ 500,000 2,173,410

Suncor 462,000 2,008,231

ExxonMobil² 387,000 1,682,220

Imperial 335,000 1,456,185

Total SA (France) 216,700 941,956

COST 183,700 798,511

Petro-Canada 144,000 625,942

Shell 141,000 612,902

Marathon 48,400 210,386

Chevron 48,400 210,386

Sinopec 45,333 197,056

ConocoPhillips 45,150 196,259

Nexen 36,150 157,138

Occidental 10 134,751

Murphy 25,000 108,671

¹ Syncrude is a JV of COST, Imperial, Suncor (ex Petro-Canada), CononcoPhillips, Murphy, and Mocal.

² Includes 70% of Imperial

Source: RMG modeling based on public disclosure and consultation with industry experts

No tailings ponds have been

fully remediated in 40 years

of production.


3.5 Health Consequences of Water and Soil Contamination Th rough the extraction process, tailings concentrate a number of toxic contaminants

naturally occurring in the oil sands deposits and bitumen, including naphthenic

acids, phenolic compounds, ammonia-ammonium, and trace metals such as copper,

zinc and iron.

Health concerns arise from the contaminants’ persistence in the environment and

consequent bio-accumulation into living organisms where serious health impacts

can occur, from tumors and cancers, to endocrine and reproduction anomalies.

Ultimately, serious concerns exist about the impact of naphthenic acids (NAs) and

polycyclic aromatic hydrocarbons (PAHs) on human health as refl ected in local

communities located downstream of the mines that are dependent on local river

water for conducting their traditional lifestyles of hunting and fi shing.

Over the last several years, several non-governmental organizations such as

Environmental Defense, WWF and Greenpeace have drawn public attention in

Canada, the United States and Europe to the toxic accumulations in the Mackenzie

watershed.67 A peer-reviewed scientifi c study by ecologist Dr. Kevin Timoney,

released in the fall of 2007, found higher than average concentrations of more than

20 substances, including arsenic and mercury, in Lake Athabasca and the Athabasca

Delta. Residual bitumen also forms a pellicle above the tailing ponds posing risks for

wildlife, such as migratory birds. In December 2009, a study by Prof. David Schindler,

a water ecologist at the University of Alberta, found that pollution from the oil sands

industry may be far greater than industry fi gures indicate. His research calculates

that approximately 34,000 tons of particulates are falling annually near the center of

67. Christopher Hatch and Matt Price, “Canada’s Toxic Tar Sands: Th e Most Destructive Project on Earth,”

Environmental Defence, Feb. 2008.

Figure LL. Land Footprint of Mineable Oil Sands

ERCB Project Development Area Attribute Time Scheme

Status (Hectares) 2008 2020 2040

Approved 150,000 Tailings (ha) 13,000 25,000 31,000

Proposed 79,000 Composite Tailings (ha) 1200 7500 6800

Net Footprint (ha) 52,000 82,000 100,000

Total 230,000 Ratio of Tailings to Footprint

(%)

25% 30% 31%

Notes:

1) Th e net footprint area includes all development including tailings and removes reclaimed lands as deemed

by the company.

2) Composite tailings are rounded to the nearest 100; all other numbers are rounded to the nearest 1000

3) Composite Tailings are higher within the 2020 scheme vs 2040 because the South Voyager ETA accepts CT

and is 3200 hectares

4) 1 km2 = 100 ha

Source: RMG modeling based on public disclosure and consultation with industry experts

Air and water emissions are

linked with cancer and other

health risks in neighboring

communities.


development. Dr. Schindler says they carry 3.5

tons of raw bitumen and carcinogenic polycyclic

aromatic compounds, which is equivalent to a

major oil spill, repeated annually, and is toxic to

some fi sh embryos.68

Dr. John O’Connor, a physician in Fort Chipewyan

from 2000 to 2007, registered three cases of

cholangiocarcinoma, a rare bile-duct cancer, in

12,000 people, which normally strikes one to

two people in a population of 100,000. He also

observed increased rates of leukemia, prostate

and lung cancer. Th e Alberta Cancer Board found

elevated cases of two other diseases in the local

population: Graves—a type of autoimmune

disease that causes over-activity of the thyroid

gland, leading to hyperthyroidism—and kidney

(renal) failure. It also showed elevated levels of specifi c cancers, including cancers of

the blood known as hematopoietics, which oncologists say includes leukemia. While

there is continued dispute over the statistical signifi cance of these fi ndings, and their

connection to oil sands pollution, the potential adverse health impacts of oil sands

production remains a signifi cant potential risk for the industry.

Aboriginal communities are taking legal action against producers and the

government regarding these environmental and social impacts, and infringement on

their recognized rights to enjoy a clean environment in order to conduct traditional

lifestyles of hunting and fi shing. (See Chapter 4 for details on precedents and

outstanding lawsuits.)

3.6 Contingent Liabilities Tailing dams have a propensity to leak. Th is was evidenced by the breach of a dam in

Tennessee accumulating coal ash deposits that spread 1.5 million cubic yards of toxic

sludge over hundreds of acres in December 2008.69 In the December 2008 report,

Th e Tar Sands’ Leaking Legacy, Matt Price of Environmental Defence researched

the fi lings of environmental impact assessments for oil sands project applications,

and calculated that in 2007, over 4 billion liters of tailings leaked out into the

environment. Th e projected leakage amount in 2012 could reach 26 billion liters.

In the H2Oil documentary screened at the Royal Ontario Museum at the Toronto

International Film Festival in May 2009, ecologist and water researcher Dr. Kevin

Timoney of Treeline Ecological Research also describes the existence of leakage.70

His research indicates that Suncor’s Tar Island Pond dam, built 300 feet above

the Athabasca River, leaks 67 liters of tailings per second, essentially making it

a continuous oil spill. Furthermore, Dr. Norbert R. Morgenstern, professor of

geotechnical engineering at the University of Alberta, has identifi ed such structural

68. Erin N.Kelly et al., “Oil sands development contributes polycyclic aromatic compounds to the Athabasca

River and its tributaries,” Proceedings of National Academy of Science, Dec. 7, 2009.

69. David Sassoon, “A Tale of Two Disasters: Coal Ash and Tar Sands Tailings,” Dec. 29, 2008,

http://solveclimate.com/blog/20081229/tale-two-disasters-coal-ash-and-tar-sands-tailings

70.. http://h2oildoc.com/home/

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Tailings ponds are leaking

and pose the risk of a

catastrophic breach.


issues with the same pond as deformation creep, or movement in a dam’s

foundation.71 In general, tailing ponds are built with sand and clay on relatively weak

foundations, such as muskeg, or on top of glacial meltwater channels. Dam failure

could result in an environmental disaster, potentially equivalent to 300 times the size

of the Exxon Valdez spill that released 11 million gallons of oil into Prince William

Sound, Alaska, in 1989.

3.7 Regulatory CatalystsGiven the environmental degradation of the boreal forest and wetland habitat, and

the public’s increased awareness of the environmental problems associated with

tailings ponds, regulatory pressure is mounting on producers. In February 2009,

ERCB, Alberta’s environmental regulator, released Directive 74, which outlined a new

tailings remediation compliance requirement. In essence, this directive specifi es that

the tailing areas for oil sands miners need to become traffi cable, i.e., solid enough to

support vehicle transit.

According to ERCB, as of June 2008, 720 million cubic meters of tailings occupied

an area of 13,000 hectares.72 Going forward, the ERCB wants to see existing fl uids

reduced, followed by progressive reclamation, meaning that the ponds will need

to be reclaimed and water recycled as producers continue to develop their mines.

As a result, mined oil sands operators will have to include tailings treatment costs

as part of their ongoing operating expenses and increase the size of their asset

retirement obligations (AROs), with some remediation fi nished over periods

of only fi ve to eight years, rather than the entire 20–40 year span of project

development.

Furthermore, the directive indicates that companies must plan better for their

tailings ponds, developing dedicated disposal areas (DDA) that have to meet

specifi c minimum un-drained shear strength within a year of deposition, and higher

standards within fi ve years. Companies fi led their fi rst set of plans with the ERCB by

Sept. 30, 2009, detailing how they are planning to meet Directive requirements; going

forward they will have annual fi ling requirements. Th e plan will be phased in over the

next four years, allowing for diff erences between mines. Th e general timetable for

remediation of tailings deposits and tailings receiving progressive recycling treatment

is as follows:

20% from July 1, 2010, to June 30, 2011

30% from July 1, 2011, to June 30, 2012

50% from July 1, 2012, to June 30, 2013, and annually thereafter

Th is phase-in means that beginning in July 2010, 20% of tailings deposits would

need to be remediated or recycled progressively. By July 2012, as much as 50% of the

produced tailings would require progressive treatment.

Companies are not being required to use any specifi c technology to meet the goals

but can choose from a number of options. Our interpretation of the rules is that

existing tailings ponds, where disposal is fi nished, must become traffi cable—i.e.,

71. Andrew Nikiforuk, “Tar Sands: Dirty Oil and the Future of a Continent,” Mar. 2008, p. 83.

72. “ERCB releases draft directive on oil sands tailings management and enforcement criteria,” Alberta Energy

Resources Conservation Board, Jun. 26, 2008.

Directive 74 calls for faster

reclamation of tailings

ponds and progressive

recycling of tailings.


able to support a specifi ed amount of weight such as vehicle transport—within fi ve

to eight years, while new ponds must be made progressively more traffi cable fi ve

years after their deposits have been extracted and be able to support reclamation

activities, such as re-vegetation.

In December 2009, the Pembina Institute published an analysis of the nine

remediation plans fi led by six companies by the fi rst ERCB deadline in September

2009. It found that only the Fort Hills Energy mine (operator Petro-Canada, now

Suncor) and the Suncor Millennium/North Steepbank mine (operator Suncor)

will be in regulatory compliance with Directive 74.73 Recent press reports indicate

that companies including Imperial Oil and Shell are attempting to convince ERCB

to extend the timelines for compliance, reinforcing the fi ndings that most mining

producers are not fully prepared to meet this directive.

Other Regulatory DriversEnvironmental compliance of mining and hazardous industries in the province

is governed by the Alberta Environmental Protection and Enhancement Act and

overseen by the ERCB. Th e Environmental Protection Security Fund of Alberta is the

mechanism that secures fi nances for the provincial remediation contingency in case of

corporate bankruptcies. As of March 31, 2009, the fund’s value was CAD $1.12 billion.74

Producers generally make contributions to the fund in the form of letters of credit.

Another regulatory catalyst comes from the development of forest protection

regulation, which could potentially result in restricted access to land for future

oil sands development. Th e provincial cabinet has recently instructed the Lower

Athabasca Regional Advisory Council to fi nd ways to protect at least 20% of its

region; currently only 6% is protected. Th e Department of Sustainable Resource

Development indicated that a plan will need to be drawn up in 2010. Th is regulation

may confl ict with current mineral leases, but the provincial government has the right

to overrule, provided that compensation is awarded.

3.8 Tailings Management OptionsTh e biggest waste remediation challenge for producers is the suspended liquid

tailings material that takes decades to settle. Although tailings settle to mature

fi ne tailings (MFT with 30%–40% solid content) in the fi rst three to fi ve years, the

settlement of the remaining FT material happens very slowly. Lack of treatment of

organic contaminants within FT has prevented complete settlement of any tailings

ponds over 40 years of oil sands industry operations.

Our conversations with industry experts suggest that tailings management has not

been successful primarily for economic, not technical reasons.75 In fact, the most

successful technological experiments date back to the 1990s. In the absence of a

73. Terra Simieritsch, Joe Obad, and Simon Dyer, “Tailings Plan Review,” Pembina Institute and Water Matters,

Dec. 2009.

74. “Environmental Protection Security Fund: Annual Report,” Government of Alberta, http://environment.

alberta.ca/documents/EPSF_AnnualReport_2008_to_2009.pdf

75. RMG conducted interviews with the oil sands companies (primarily Suncor and Imperial), environmental

engineers (e.g. ERM, Bennett Environmental, Fiton Technologies), and research (e.g. Randy Mikula, team

lead at CANMET Energy Tech Centre in Devon, Alberta, Natural Resources Canada).

Only one oil sands mining

operator expects to be in

compliance with Directive

74.


regulatory obligation or business rationale, producers for the most part have simply

stored tailings in large containment areas. Th e new impetus for operators to extract

water from tailings is the increased operational requirement of water for continued

growth in production. Given the increased risk of water shortages discussed in

Chapter 2, tailings management for producers has become synonymous with water

management.

A number of tailings management methods are in use, including some that are at the

experimental, pilot testing stage:

1. Water capping: Th is is an historical reclamation practice where tailing ponds

are capped with fresh water to form end-pit lakes. Th e industry claims that tailings

initially will stay separated due to the diff erent nature and densities of the two

liquids. Th en, in the long run, the two layers are supposed to mix into a remediated

state that will ultimately support viable ecosystems.

Th is option is highly controversial and unlikely to receive permanent regulatory

approval. It is the lowest-cost alternative, and is in fact, not reclamation, but rather

a long-term storage option. It was the best available technology for managing

tailings before 1989, when the Albertan government fi rst undertook an initiative

to encourage the industry to remediate rather than store tailings. Nowadays, this

method is generally considered to be obsolete. In 2008, the Tse Keh Nay community

successfully set a legal precedent in a case against a Canadian gold miner, Northgate

Minerals, which in 2003 had proposed to store acid tailings in the Amazay Lake

in British Columbia. Although this precedent aff ected another mining industry in

another province, the court recognized that the environmental assessment process

underestimated the risks associated with using aquifers for waste storage, and

banned the long-term storage of acid tailings in the Amazay Lake as part of that

mine’s expansion.

2. Composite Tailings/Consolidated Tailings/Non-segregated Tailings

(abbreviated as CT): Th is technique is largely based on chemical treatment of tailings

to achieve solidifi cation. Essentially, mature fi ne tailings (MFT) replace water found

in sand tailings. Suncor pioneered this treatment process in 1994 with an addition of

gypsum and coarse sand into the tailings mix. Alternatively, CO2, lime, acid & lime,

and polymer can be used in place of gypsum.

One note of caution is that CT production competes for sand required for dike

construction in tailings ponds. Th is may compound the challenge of tailings

management if CT becomes a preferred treatment option. In eff ect, an MFT

analogue is being used to prevent accumulation of MFT in the fi rst place, making

the control process more complicated.76 Suncor is moving away from using the CT

process, and is instead proposing to incorporate MFT Drying into its regulatory

compliance plans.

3. MFT Drying and Accelerated Dewatering: In October 2009, Suncor announced

an alternative method to accelerate its tailings remediation operations. Th is is

achieved by adding a polymer that binds to the tailings. Th e resulting slurry is then

spread on a slightly graded slope that allows the water to run off and be treated

76. R.J. Mikula, V.A. Munoz, O.Omotoso, “Water Use in Bitumen Production: Tailings Management in Surface

mined Oil Sands,’ Natural Resources Canada, CANMET Energy, Jun. 17, 2008.


and recycled. Th e slurry is spread thin to further accelerate the drying process. As a

result, Suncor expects to be able to eliminate the need for long-term tailings storage

and return solid tailings to the mines as they are generated resulting in revegetated

surfaces in 7–10 years post disturbance, whereas prior tailings pond settlement

methods took more than 30 years before land reclamation could begin. Over

the next two years, Suncor will invest CAD $1.2 billion in this proprietary tailings

remediation process. While this will increase the company’s near-term operating

expenses, it will reduce its long-term asset retirement obligations by cutting the time

requirement for land reclamation by more than half. 77

4. Carbon dioxide (CO2) injection: Th is method, used by CNRL, injects waste CO2

into the liquid tailings before the slurry enters a pond, where the CO2 reacts to form

carbonic acid. Th is changes the pH of the tailings mixture, then allows the fi ner clays,

silts and sand to settle, leaving clearer water for recycling.

5. Bioremediation: Th is process uses microbes and nutrient biostimulants to convert

organic contaminants into inorganics such as carbon dioxide and water. It allows for

recycling of the freed water and settlement of the FT suspensions that are no longer

bound with clay and petroleum residue.

Once the liquid tailings have been disposed of, the treated MFT is covered with

returned overburden to conceal the open pit mines, and eventually re-vegetated.

3.9 Increased Salt BudgetsAnother water management issue that is a growing concern for oil sands producers

is the accumulation of salt as more recycled water is used in place of makeup

(fresh) water. Th is is especially true for in-situ producers using steam-assisted gravity

drainage (SAGD) systems; an average producer can generate 33 million pounds of

dissolved salts and water-solvent carcinogens annually.78 As the salt concentration in

recycled water increases, it gradually reduces the effi ciency of the bitumen extraction

process. With the amount of makeup water being reduced, the concentration of

chloride and divalent ions in the recycled water will continue to rise. Eventually, the

extraction recovery process may become impaired to the point where the recycled

water needs to undergo some further form of treatment.

According to the study by Natural Resources Canada, technologies are available for

this purpose, but they are expensive and have not yet been proven for processing

water in hydrocarbon-contaminated oil sands.79 One option involves treatment

of ionic components in recycled water while maintaining zero water discharge.

Dissolved salts are extracted in this process and shipped to landfi lls. However, organic

contaminants also present in the recycled water interfere with the removal of the

ionic components. Th erefore, a secondary treatment option is to remove the organic

contaminants for discharge into a surface water body and allow for consecutive

withdrawal of fresh water for makeup purposes. But this also has its drawbacks. Th e

need for makeup water goes against the directive to reduce the use of freshwater in

the oil sands extraction process. In addition, the organic contaminants removed in

this process include natural surfactants that enhance the bitumen recovery process.

77. Gordon Lambert, Suncor Corp., Personal communication, May 12, 2010.

78. Ibid.

79. Ibid.

Bioremediation may be

a preferred method for

treating tailings.


Th is works against the other objective of the treatment process, which is to maintain

suffi cient levels of bitumen recovery in recycled water. Accordingly, the preferred

solution would avoid this secondary treatment, but it compounds the primary

challenge of reducing the salt build-up in recycled saline water. In eff ect, in-situ

producers are caught in a “catch-22” when it comes to treatment of saline water.

3.10 Tailings Remediation CostsTh e replacement of oil sands overburden and re-vegetation is not a complex issue,

and the costs are well-documented. For example, in 2006 Syncrude spent a total of

CAD $30.5 million on reclamation activities on 267 hectares (ha), which works out to

about CAD $114,000/ha.80 Another estimate relates to the re-vegetation only, at CAD

$200,000/ha, based on 10 plants per square meter at CAD $2/plant.81

To put these fi gures in perspective, we reviewed the asset retirement obligation

(ARO) of Suncor, which is an oil sands operator that provides ARO disclosure specifi c

to its mining operations. Suncor’s total land impact is 12,800 ha82, and hence Suncor’s

2008 undiscounted asset retirement obligation of CAD $3.49 billion works out to

$271,000/ha of disturbed land. Th is leaves CAD $71,000/ha for remediation activities

other than re-vegetation, including treatment of tailings on 36%, or 4,600 ha, of its

impacted land.

In contrast to re-vegetation costs, tailings treatment is not a straight-forward matter.

Our review of publicly available information found no references to such costs.

Overall, transparency is lacking from the industry with respect to detailed aspects of

tailings management options, including existing costs (in the case of CT at Suncor

and Syncrude) and estimated costs. Th is makes it diffi cult to estimate compliance

costs of fi nal tailings remediation. Required corporate disclosure associated with

Directive 74 should help answer questions relating to the engineering design and

timetables for progressive reclamation; however, exact costs will be kept confi dential

by operators. Accordingly, investors may wish to request more detailed cost

information on existing tailings management operations, such as CT, MFT drying, and

CO2 injection, and possibly new treatment options such as bioremediation.

In any event, there is growing recognition that the fi nal costs of tailing reclamation

will be high. For example, industry groups such as CAPP and the Alberta Chamber of

Resources lobbied extensively against the introduction of wetlands protection by the

Wetlands Policy Project Team in the summer of 2008, citing costs in the billions of

dollars. Th is is not surprising, as wetlands are complex ecosystems to restore.

Because full remediation will not occur until fi ne tailings (FT) are settled out, no

oil sands tailing pond has yet been fully reclaimed. While we could not reasonably

estimate costs of CT or MFT drying, which are being developed by the operators in-

house, these processes may not be able to achieve the objectives of Directive 74 in

any case (although Suncor’s new proprietary method intends to do so). If the ERCB

forces oil sands producers to expedite remediation of existing tailings ponds where

deposits have ceased and to progressively recycle tailings liquids, these companies are

likely to see:

80. Jennifer Grant et al., “Oil Sands Reclaimation: Fact or Fiction?”, Pembina Institute, Mar. 2008, p.44.

81. Ibid.

82. ERCB, 2008.

Directive 74 will add to the

operating costs and Asset

Retirement Obligations of oil

sands mining operators.


an increase in asset retirement obligations (ARO), and consequently balance

sheet leverage, as more expensive technologies are expected to speed up

solidifying the FT and the timeframe is likely to be more condensed, perhaps to

as little as fi ve years. Th is means that there would be less time for the liability to

accrue on the balance sheet in comparison with the 20-40 years that is typical

for most oil sands reclamation;

an increase in operating costs, and hence income statement impact, associated

with recycling water on a going-forward basis; these higher operating costs

are likely because the ERCB is intent on progressive remediation, which means

much faster recycling of the FT liquids.

Costs of bioremediation: Our analysis concludes that bioremediation is a

preferred treatment option because it treats wastewater early in tailings discharge,

reduces sedimentation time and eliminates the need for long-term pond storage.

Th is method also helps resolve toxicity issues and the risk of downstream and

underground water contamination.

Because bioremediation has not been used extensively in the oil sands industry,

its costs are not generally included in existing AROs or operating cost structure.

Accordingly, we sought tailings treatment cost estimates from experts that perform

bioremediation services in other segments of the petroleum industry. Our research

indicates that bioremediation costs will be in the CAD $15 to CAD $50/ton range

for the existing solid tailings (i.e., ARO eff ect), while ongoing operating costs could

experience a CAD $1.25 to CAD $4.17 per cubic meter (or CAD $1.46 to CAD $4.86

per ton) increase if progressive remediation/recycling is required (i.e., operating cost

eff ect). In terms of per boe production costs, the operating cost increase would be in

a range of CAD $1.21 to CAD $4.05 per barrel of production.

Th e high-end fi gure of CAD $50/ton for solids remediation cost (i.e. ARO eff ect) is

broadly accepted within the industry, while the low end comes from consultation

with a bioremediation expert, Fiton Technologies.83 Th is low-end quote assumes that

Fiton Technology’s proprietary biocatalysis process, when applied to existing tailings

accumulations, would produce economies of scale and drop the remediation cost to

CAD $15/ton.

For the progressive liquids remediation (i.e. operating cost eff ect), we again used

quotes from Fiton to produce a low- and high-end estimate. We believe there could

be a signifi cant drop in the progressive/ongoing costs of waste remediation per unit

of production because it is easier to treat the waste as it comes out of the plant, as

opposed to dealing with decade-long waste accumulations. Some of the equipment

and infrastructure to help the progressive treatment process already is in place on

some sites. Th e tailings would need to be only handled once as they come out of the

waste pipe, and less treatment product would be required to penetrate the newly

produced, fl uidized mixture. Once the waste accumulates, it becomes harder to

recover and recycle water, and more bioremediation agents need to be introduced

into the tailings material to treat the contaminants.

We regard these cost estimates to be conservative, given the precedent from clean-

up of tar contamination at the Sydney Tar Pond. Th is clean-up of 700,000 tons of

83. http://www.fi ton.com


contaminated soil cost a total of CAD $400 million works out to CAD $570/ton,84

or 11 times higher than our high-end soil remediation estimate.

To calculate ARO obligations of individual oil sands miners that need to remediate

existing tailings, we reviewed four projects with tailings accumulations that are

as much as 40 years old. Th rough fi lings with regulatory agencies obtained by the

Pembina Institute, we derived information in Figure MM for these producers as of

May 2008.85

We then applied our solid tailings bioremediation estimates per project and per

producer, and compared the resulting ARO obligation to what producers currently

have booked on their balance sheets. In this modeling exercise, Canadian Oil Sands

Trust (COST) and Imperial Oil (IMO) are projected to have the greatest balance sheet

exposure in terms of remediating existing tailings. To meet the expedited clean-up

schedule under Directive 74, it is assumed that these companies would assume more

liability on their balance sheets in the form of growing AROs. Th is would raise COST’s

debt-to-capital ratio by at least 10% in the low-cost scenario, and by as much as 26%

in the high-cost scenario. Similarly, IMO’s balance sheet leverage would increase by at

least 6% and possibly as much as 17% in the respective scenarios (see Figure NN).

To estimate the operating expense of producers that stems from this progressive

remediation requirement, in Figure OO we have compiled the daily tailings

production estimates of the four mining projects, based on the corporate disclosure

of 2007 synthetic crude production.

Finally, we applied our low- and high-end cost estimates for on-going tailings

bioremediation to each of these producers. Figure PP shows that Suncor (SU) would

experience by far the most dramatic negative impact. Th e increased operating

expense could reduce the company’s earnings in a range of 26–104%, compared to

2009 consensus earnings estimates. (Th ese fi gures do not include its 2009 merger

with Petro-Canada, which reduces this impact on its balance sheet. It also does

not refl ect SU’s recent expanded investment in MFT drying operations, which the

company says could speed the tailings settlement process and reduce its projected

84. See Sydney Tar Ponds Agency, http://www.tarpondscleanup.ca/index.php?sid=2

85. RMG’s correspondence with Pembina Institute. Project-specifi c tailings footprint comes from digitized GIS

data maintained by ERCB.

Figure MM. Tailings Inventory (as of May 2008)

Tailings Area (hectares) % of impact

Tailings Inventory

(m3)

Tailings Inventory (in bbls)

Tailings Inventory

(tons)

Syncrude 7,100 55% 393,230,769 1,759,858,990 337,427,974

Suncor 4,600 35% 254,769,231 1,140,190,332 218,615,307

AOSP 1,000 8% 55,384,615 247,867,463 47,525,067

CNR 300 2% 16,615,385 74,360,239 14,257,520

Total 13,000 720,000,000 3,222,277,024 617,825,868

Source: Provincial government fi lings through Pembina Institute; RiskMetrics’ conversions

Mining operators with the

highest tailings inventories

face the greatest impacts on

their balance sheets.


asset retirement obligations.) Before its merger with PetroCanada, Suncor was the

largest pure-play mined oil sands producer, with the greatest volume of accumulated

tailings when its participation in the Syncrude partnership is taken into account.

COST, with the largest ownership stake in Syncrude, has the second-largest operating

expense exposure, with earnings reductions ranging from 8–33% relative to 2009

earnings estimates, depending on whether the low- or high-cost estimate is used.

Because the other oil sands producers have smaller volumes of tailings, or are more

diversifi ed integrated oil and gas companies, their potential earnings exposure is far

less than that for SU or COST (see Figure PP).86

86. Detailed calculation tables are available in the Oil Sands Tailings Pond Remediation Costs Understated, a

joint ESG Analytics – CFRA report published by RiskMetrics Group on Dec. 22, 2009.

Figure NN. Projected Increase in Leverage: Debt/Capital Ratio (2010)

Source: RMG research

30%

25%

20%

15%

10%

5%

0%COST IMO SU MUR NXY XOM CNQ

Low case

High case

Figure OO. Daily Liquid

Tailings Production (2007)

Oil Sand PartnersLiquid Tailings

(m3/d)*

Syncrude 296,455

IMO (25%) 74,114

COP (9%) 26,681

MUR (5%) 14,823

SU (12%) 35,575

NXY (7%) 20,752

COST (37%) 109,688

Nippon (5%) 14,823

SU 192,359

SU + SU Syncrude 227,934

AOSP 133,939

RDS (60%) 80,363

CVX (20%) 26,788

MRO (20%) 26,788

XOM (70% of IMO) 51,583

CNQ 42,309



Figure PP. Estimated Decline in Net Income (2009)


0%

5%

10%

15%

20%

25%

30%

35%

COST IMOSU MURNXY XOMCNQ

Low case

High case

MRO COP RDS CVX

104%

Suncor and COST could

see their earnings decline

substantially if they don’t

fi nd new solutions to treat

tailings.


4. Aboriginal Rights and Oil Sands Development

4.1 Historical BackgroundA growing concern to investors in the oil sands is the industry’s tenuous relationship

with local indigenous communities in Canada. Virtually all oil sands companies

operate in areas overlapping with Aboriginal traditional territories.

Th e Canadian government signed a number of treaties with Aboriginal communities

(known in Canada as First Nations, Metís and Inuit) during the 19th century that

secured the oil-rich land for the Crown Domain of the Dominion. Th ese treaties,

dating back to 1876, guaranteed these Aboriginal communities the right to conduct

their traditional lifestyles on these lands, namely the basic rights to sustain their

livelihoods through hunting and fi shing. Th e Canadian Constitution, signed by the

Prime Minister Pierre Trudeau and the Queen of Britain in 1982, reinforced these

treaty protections.

4.2 Interpretation of Indigenous RightsIn practice, Canada’s Constitution requires that the national and provincial

governments have the duty to consult and accommodate the recognized rights

of Aboriginal communities.87 Aboriginal leaders in the region have passed joint

resolutions calling for a moratorium on oil sands project approvals until strategic

watershed and land use planning is completed, and committing “to take all steps in

our power to protect our lands, sustain our communities and assert our rights.”88 Oil

sands producers have no formal role in resolving this dispute, as this requires nation-

to-nation negotiations between the Crown (Canada and Alberta) and the Aboriginal

communities involved. Nevertheless, oil sands producers can help their cause by

being proactive in Aboriginal engagement.

A recent survey of 11 oil sands producers shows mixed results in this regard.89

Only about a third recognize treaty rights in their Aboriginal policies, and none

incorporate the principle of Free, Prior and Informed Consent (FPIC). FPIC is a core

principle in First Nations’ expectations of consultation. It describes respecting the

right of Aboriginal people to be fully informed about exploration, development and

closure activities on a timely basis, to approve operations prior to commencement,

and if necessary to refuse consent. Although FPIC is not yet in widespread practice,

it off ers the most robust strategy to mitigate the risks of Aboriginal opposition to oil

sands projects.

87. For more on the precedent that describes the right to consult and accommodate, see: Haida Nation vs.

British Columbia http://www.canlii.org/en/ca/scc/doc/2004/2004scc73/2004scc73.html

88. “First Nations demand oil sands moratorium,” Edmonton Journal, Aug. 18, 2008; “First Nations

communities prepare for battle over water, culture,” Fort McMurray Today, Aug. 27, 2008.

89. “Lines in the Sands: Oil Sands Sector Benchmarking,” Northwest & Ethical Investments published by Ceres,

Nov. 2009.

Aboriginal communities

are granted substantial

protection and rights under

the Canadian constitution.


4.3 Legal CasesGiven the extent of environmental degradation in the region and the health impacts

on local communities, the Aboriginal people have a strong case that they are being

prevented from exercising their rights to traditional lifestyles guaranteed to them by

the Canadian Constitution. Th e communities below have gone to court to fi ght for

their right to a subsistence livelihood:

Fort Chipewyan First Nation

Mikisew Cree Nation

Beaver Lake Cree

Tsuu T’ina Nation

Samson Cree Nation

Th ese cases focus primarily on land rights and titles. Th e amount of toxicity or

other environmental impact is irrelevant, once it passes the threshold of impeding

traditional lifestyle. Th e major legal challenge, in other words, is to provide evidence

showing abridgement of these rights. Once it is established that the community

is being prevented from exercising its rights to hunt and fi sh, the extent of

environmental damage caused by oil sands operations on these lands is largely

immaterial.

Th ese legal cases do not involve claims to the land for commercial purposes, because

the First Nations and Metís do not possess these rights. Th e majority of the cases are

fi led against the provincial and federal government over failed consultation with the

community, although in several instances the legal cases also name corporations as

defendants in the failed consultation. In 2008 alone, three legal challenges were fi led

in courts by the First Nations over failed consultation.

Of note is a legal precedent set by the law fi rm of Jack Woodward – Woodward & Co

in Victoria, British Columbia, brought on behalf of the Tse Keh Nay community in

2008. As noted in Chapter 3, the court found in this case that a fl awed environmental

impact assessment (EIA) process was used in connection with proposed tailings

disposal into the community’s Amazay Lake.90 Although the case was brought

against a Canadian gold miner, Northgate Minerals, it demonstrated the impact that

First Nations can have using the Canadian legal system.

Also, in March 2008, the Beaver Lake Cree Nation fi led a lawsuit against the

government of Alberta, calling for an injunction to block more than 16,000 permits

related to lands that are used for hunting and fi shing and that have been disturbed

by oil sands projects. Consequently, in February 2009, the Co-operative Bank (UK)

announced that it would provide $71,000 to fund evidence-gathering for this case.

Our meetings with lawyers in the fall of 2009—Barry Robinson, Ecojustice (formerly

Sierra Legal Defense Fund), and Drew Mildon with Woodward & Co.—found that

several other social activist organizations, such as Oil Sands Environmental Coalition,

Ducks Unlimited and EcoJustice have challenged the Crown’s and producers’ due

diligence as they embarked on licensing and operating their oil sands projects. Th e

Ducks Unlimited case has gathered particularly negative publicity for Syncrude, which

90. See: Tse Keh Nay website, (VRI) http://tsekehnay.net/index.php?/amazay

Legal challenges to oil sands

projects are growing.


is pleading not guilty to a CAD $800,000 criminal charge imposed for 1,000 migrating

ducks that became trapped and died in a Syncrude tailings pond in April 2008.91

Successful litigation in the above-mentioned cases could produce a setback for

producers, ranging from project delays to outright invalidation of leases and project

shut-downs. It could also jeopardize eff orts to build new oil sands pipelines to

Canada’s west coast to open up new export markets. As noted in Chapter 1, nine

Coastal First Nations governments announced their opposition to the Northern

Gateway pipeline proposed by Enbridge Corp. in March 2010. Th is would be the

fi rst pipeline to bring oil sands production from Alberta to port terminals along the

British Columbia coast. Th e First Nation groups cited concerns over the possible

lasting and devastating eff ects of an oil spill, and said that the Athabasca Chipewyan

Cree First Nation located near Alberta’s oil sands backed their declaration.

4.4 Failed Stakeholder ConsultationOil sands producers have several ways in which to engage Aboriginal communities

in their project development activities. Th e most basic of these is a Memorandum

of Understanding (MOU) that outlines basic parameters for their relationship and

commits both sides to discussing a commonly identifi ed set of objectives. A signed

MOU is not necessarily an indicator of community support for a project, however,

but merely a signal that substantive discussions will place. A more engaging process

is an Impact and Benefi t Agreement (IBA) that spells out the responsibilities of the

company to mitigate project impacts and deliver project benefi ts (e.g., revenue

sharing, procurement and employment opportunities). In return, the community

may provide consent provisions that are a strong indication of ongoing project

support.

Stakeholders in Alberta have set up several elements that foster the progression of

the consultative process, including the Alberta First Nations consultation guidelines92

and All Parties Core Agreement (APCA).93 Th e APCA is an eff ort to bring together

impacted First Nations and industry representatives for meaningful dialogue around

development issues. Five First Nations of the Athabasca Tribal Council are receiving

funding support for Industry Relations Corporations (IRCs) to identify key concerns

about development in their traditional territories and represent those concerns

eff ectively in consultations with the oil sands industry.

Some previously established stakeholder consultation eff orts have encountered

diffi culties. A prime example is the Cumulative Environmental Management

Association (CEMA), a group created in 1999 to address environmental issues

surrounding oil sands development in Alberta. It is comprised of more than 40

stakeholders, including businesses, indigenous groups, environmental groups and

government offi cials.94 In February 2008, the group submitted a letter requesting a

partial moratorium of oil sands production covering approximately one-sixth of the

Athabasca oil sands region. However, upon review, this letter was not acted on by the

Alberta Department of Energy.

91. John Loring, “Alberta’s Tar Sands and the Dead Duck Trial,” Green Ink, Mar. 10, 2010. http://greeninc.blogs.

nytimes.com/2010/03/10/albertas-tar-sands-and-the-dead-duck-trial/

92. See: http://www.aboriginal.alberta.ca/571.cfm

93. See: Athabasca Tribal Council, http://ryanjanvier.com/atc/about-atc

94. See: http://www.cemaonline.ca/

First Nations governments

oppose a new pipeline

that would bring oil sands

production to port terminals

on Canada’s west coast.


Some CEMA members are oil sands producers that voiced disagreement with the

letter. For example, ConocoPhillips, a CEMA member, said in a statement that

it is “supportive of the general intent expressed in the letter that was submitted

by CEMA,” but that existing lease-holders must be respected and be allowed to

maintain the rights to develop currently held leases. “We share some of these

concerns along with a number of other members of industry,” the company

statement said.

In August 2008, three of the main NGO supporters of CEMA—the Pembina Institute,

the Toxics Watch Society of Alberta, and the Fort McMurray Environmental

Association—pulled out of the association. In a press release, these organizations

asserted that after “eight years of eff ort and consistent failure to meet deadlines

for recommending systems to protect the region’s environment, CEMA has lost all

legitimacy as an organization and process for environmental management in the oil

sands.”

4.5 Summary of Legal RisksGiven the deteriorating relationship among oil sands stakeholders and the growing

number of legal actions taken by First Nations in Alberta and British Columbia, the

risks of unfavorable court rulings for oil sands producers are increasing. While the

outcome of future court rulings remains to be determined, this much is clear: while

other cases involving review of environmental risks generally are more qualifi ed and

involve a range of possible outcomes that oil sands producers can negotiate and

possibly work through, the First Nations’ challenges lend themselves to more binary

outcomes. Either a producer is able to maintain its lease and continue operating

business as usual, or the lease may be annulled and the producer has to abandon the

project altogether.

Accordingly, the implications of First Nations’ legal intervention loom large in the

future of the Albertan oil sands industry, and bear close watching by investors.


5. Conclusions

5.1 Finding the Right Growth TrajectoryTh e ongoing controversy and unresolved questions surrounding oil sands

development in Alberta have led to calls for a moratorium on new projects. A

number of Aboriginal leaders in the region want project approvals put on hold until

strategic watershed and land use planning is completed, and they receive assurances

that they will be properly consulted with their constitutional rights respected.95

Some Canadian investor groups, such as Northwest & Ethical Investments, based

in Vancouver, British Columbia, support this call for a new-project moratorium.96

Meanwhile, a group of investors, with backing from some major U.S., European

and Australian institutions, has fi led shareholder resolutions with four major

oil sands producers in 2010 asking for better disclosure of the economic and

environmental risks associated with oil sands development.97 A similar resolution

fi led with ConocoPhillips in 2009 received strong investor support—30.3% in favor,

representing $12.8 billion in share value.

Falling oil prices in late 2008 prompted a de facto moratorium for some oil sands

producers that have canceled or indefi nitely deferred many new projects. However,

global oil prices have since rebounded, and prospects for new oil sands development

have improved. Several prominent players, including Cenovus and Suncor (which

merged with Petro-Canada in summer 2009 to create Canada’s biggest oil company),

have signaled their intent to maintain oil sands development as a core business

activity. Imperial Oil has also received a corporate go-ahead to launch a giant new

mining project, and in April 2010 PetroChina International Investment launched a

public off ering of its 60% stake in Athabasca Oil Sands Corp.’s in-situ projects.98

In eff ect, these companies are betting that demand for higher-priced oil is here to

stay. To justify investments in new oil sands development, oil needs to maintain a

global price of at least $65/bbl and possibly as high as $95/bbl. A recent forecast from

the U.S. Energy Information Administration (EIA) projects that oil prices will continue

to rise and reach $130/bbl by 2030 (in constant 2009 dollars). Th is would raise oil

sands production volume up to 4.2 mbbl/d by 2030 under a high economic growth

forecast (see Figure QQ), according to EIA. Th is is more than double the volume of

existing operating capacity and projects under construction. Th is EIA estimate is also

500,000 bbl/d above the Growth scenario of 3.7 mbbl/d that has been presented

in this report. At $200/bbl, the EIA estimates that oil sands production could reach

as high as 6.5 mbbl/d by 2030—far above any of the scenarios presented. However,

we regard this is as a highly unrealistic and economically and environmentally

unsustainable scenario, for reasons outlined earlier.

95. “First Nations demand oil sands moratorium,” Edmonton Journal, Aug. 18, 2008; “First Nations

communities prepare for battle over water, culture,” Fort McMurray Today, Aug. 27, 2008.


Ceres, Nov. 2009.

97. Hugh Wheelan, “Shareholder Abstention on Oil Sands at BP Fires Warning Shot,” Responsible Investor, Apr.

16, 2010.

98. “PetroChina-controlled Athabasca Oil Sands to be listed on Toronto Stock Exchange,” Xinhua News

Agency, Apr. 2, 2010.

Oil sands development is

drawing increasing scrutiny

from institutional investors.


5.2 Shrinking Window of OpportunityGiven such a wide range of estimates, the modeling assumptions used in this report

(and the 2009 CAPP survey of oil sands producers on which they are based)99 may

be viewed as conservative. However, we believe that global market conditions may

have diffi culty sustaining oil prices above a range of $120–$150/bbl for any length

of time. Th at is because high oil prices historically have slowed economic growth

and depressed commodity prices while stimulating investments in energy effi ciency

and alternative fuels. Carbon emission limits expected to take hold in the next two

decades also are likely to reduce global demand for oil and other carbon-intensive

fuels as they add to their price.

Accordingly, oil sands producers are operating in a narrow fi nancial window that may

be shrinking over time. Th ey want to avoid reaching an oil price ceiling, like the one

at $147/barrel in July 2008 that contributed to the oil price collapse below $40/barrel

by the end of that year. But they also want to be confi dent of an oil price fl oor—

now estimated at $65–$95 per barrel—to justify such long-term, capital-intensive

investments. Oil markets have rarely maintained such stability and orderly price

movements; this is one of the inherent risks in investing in this volatile commodity.

Beyond global market conditions, oil sands producers must also be wary of their

own rising production costs. A combination of growing demand for natural gas,

onset of carbon pricing and low carbon fuel standards will eff ectively raise the fl oor

price for production of synthetic crude oil. Growing water requirements and land

99. “Crude Oil: Forecast, Markets & Pipeline Expansions,” Canadian Association of Petroleum Producers

(CAPP), 2009.

Figure QQ. Oil Sands Production Projections

Source: U.S. Energy Information Administration, 2010 Energy Outlook

EIA IEO 2009 Projections: Canada Oil Sands

7

6

5

4

3

2

1

0

19902006

20072010

20152020

20252030

mb

bl/

d

High Oil Price

Low Oil Price

High Economic Growth

Low Economic Growth

Oil sands producers face

rising fl oor costs and falling

ceiling prices that are

shrinking their window of

opportunity.


reclamation regulations will add on another layer of additional costs. Th e biggest wild

card, however, may be relations with First Nations and other Aboriginal communities

whose exercise of constitutional rights has the potential to stop some oil sands

projects and pipelines dead in their tracks.

Th is report has addressed each of these risks. We conclude that oil sands producers

banking on rapid growth are taking a big gamble. Over the long time horizon of these

capital-intensive investments, market and energy policies could turn against their

projects for reasons largely beyond their control. Th is argues for a more incremental

approach that allows market signals to become clearer, carbon risks to be examined

more thoroughly, and technologies and mitigation strategies to evolve so that risk

exposures are limited and better managed. To the extent that the oil sands industry

is moving from traditional, mega-style mining projects to more modular in-situ

projects, this more refl ective, incremental approach may already be evolving.

Nevertheless, there is good reason to believe that oil sands producers fully intend to

step up the pace of development as long as they believe market forces will support

further expansion. Investors should be concerned and asking questions on whether

such strategies lose sight of longer-term risk issues that may ultimately compromise

oil sands projects. Accordingly, we off er this summary of the major risks that oil sands

companies and their investors must be prepared to address.

5.3 Natural GasOil sands have a low energy return on energy invested (EROEI). With an EROEI of 7:1

vs. 22:1 for conventionally produced oil, it takes three times more units of energy to

e xtract bitumen from oil sands than oil from conventional wells. After upgrading and

refi ning, the EROEI of oil sands falls even further to just 3:1.

Natural gas is the primary fuel used throughout the oil sands extraction and upgrading

process, with in-situ producers especially reliant on steam for injection into deep

underground deposits. By 2015, oil sands producers’ demand for natural gas could

triple, accounting for 15% of Canada’s consumption of this clean-burning fossil fuel.

However, there will be many competing demands for natural gas, as carbon pricing

increasingly favors use of this low-carbon fuel for power generation and transportation.

As a result, oil sands producers face the risk of higher purchasing costs for this key

energy input. At the same time, more pipeline infrastructure will be needed to deliver

the ever-growing quantities of natural gas that oil sands producers require.

For forward-looking investors, a key metric to track is the steam-to-oil ratio of in-situ

projects. Some producers like BP claim that future technological improvements will

enable new projects to achieve a better than 2:1 SOR, meaning less than two units

of steam would be needed for each unit of bitumen produced. Th is compares with

a current average of approximately 3:1 SOR for operating projects in the Athabasca

deposit. A declining SOR would have multiple benefi ts, as it would reduce the

amount of natural gas and water required to produce the steam, and limit exposure

to the costs of water recycling and any future restrictions on absolute water use.

However, SORs from operating projects are often higher than their design SORs.

Several new projects have design SORs of 7:1 or 8:1 due to the deteriorating quality

of in-situ deposits, with greater amounts of steam and energy required. Accordingly,

investors who gain access to SOR data would be better able to determine whether

in-situ producers are facing rising or diminishing returns with their new projects.

Oil sands producers’

demand for natural gas

competes with other uses of

this clean-burning fuel.


5.4 Carbon EmissionsTh e large energy requirements of Canada’s oil sands producers also make them

prodigious emitters of carbon dioxide, the principal manmade source of greenhouse

gas emissions. Th e oil sands industry is Canada’s fastest growing source of GHG

emissions, with its emissions projected to grow from 5–15% of the nation’s total by

2020. At the same time, Canada, like other industrial nations, has pledged to reduce

its GHG emissions substantially over time, perhaps by more than 80% by 2050. Th is

puts the oil sands industry on a collision course with this key, long-term national

objective.

Short of curtailing production, oil sands producers have relatively few options to

reduce their GHG emissions. Some extraction techniques, such as toe-to-heel air

injection (THAI), have the potential to reduce dependence on natural gas for steam

production; but this is still an experimental production technique. Nuclear power is

another possible replacement for natural gas, but no oil sands producers have current

plans to pursue this option. Th at leaves carbon capture and sequestration (CCS) as

one of the only remaining technological solutions to reduce the industry’s growing

GHG emissions.

Since 2007, the Province of Alberta has placed a CAD $15/ton levy on CO2 emissions

and made CAD $2 billion available to support commercial demonstration of CCS

technology. However, these measures to date have prompted only one oil sands

producer, Shell Canada, to move forward with a CCS demonstration project. Few

portions of oil sands production yield suffi cient concentrations of CO2 to make the

process economic. Even these are expensive solutions that capture only 10-30% of

the entire CO2 waste stream. Alberta’s CCS Task Force estimates that the initial cost

of CCS at oil sands upgraders and hydrogen facilities is in a range of about CAD $75-

$115/ton of CO2, taking into account a $15–20/ton levy on CO2 emissions.100

Moreover, Alberta’s oil sands are not in an ideal geographic location to support

carbon sequestration. Extensive pipeline networks would have to be built to ship

the CO2 to underground reservoirs located up to 1,000 miles away. A host of legal,

regulatory and permitting issues also still have to be overcome. Liability issues

present a particular challenge, since the sequestered carbon would need to remain

safely stored underground for hundreds or even thousands of years.

Even if the oil sands industry eventually achieves a higher CO2 capture rate of 30-50%

by 2050, the remaining upstream emissions from growing rates of production could

exceed the entire carbon budget for all of Canada if the government remains intent

on an 80% cut in total emissions by 2050.101 Th is also means that Canada would need

a substantial pool of carbon off sets to bring oil sands producers’ emissions in line

with these national targets. It is unclear whether a carbon trading market in Canada

could emerge fast enough and grow large enough to address these excess oil sands

emissions.

100. “Accelerating Carbon Capture and Storage in Alberta,” Alberta Carbon Capture and Storage Development

Council, Oct. 2008.

101. “Carbon Capture and Storage in the Alberta Oil Sands — A Dangerous Myth,” World Wildlife Fund and

Th e Co-operative Bank, Oct. 2009. [Th e referenced projection for 2050 assumes that Canadian oil sands

production reaches 5.8 mbbl/d at that time.]

Carbon emissions from

Alberta’s oil sands could

triple by 2030.


All of this leaves critical, unanswered questions for investors. Th ese include whether

oil sands companies are:

placing an assumed price on oil and carbon emissions in their production forecasts

projecting future prices and availability of locally sourced natural gas

investing in R&D and new technologies to reduce carbon emissions, including CCS

making plans to purchase credit allowances to off set their carbon emissions

supporting the creation of a large carbon trading market with aff ordably priced

off sets

setting explicit targets and timetables to reduce the GHG intensity and overall

emissions of their operations

5.5 Low Carbon Fuel StandardsIn addition to limits that may be placed on upstream CO2 emissions from oil sands

production, limits may also be placed on downstream CO2 emissions when the fuel

is burned. Such limits are likely to be in the form of Low Carbon Fuel Standards

(LCFS). More than half of the U.S. states and four Canadian provinces are weighing

the adoption of LCFS to reduce the carbon intensity of some petroleum fuels.

California already has an LCFS in place that requires a 10% reduction in the average

carbon intensity of motor vehicle fuels by 2020; the Northeast may soon follow suit.

Together, these states comprise one-quarter of U.S. demand for transportation fuels.

Adoption of LCFS would place oil sands producers at a disadvantage to conventional

petroleum producers, because their synthetic crude oil (SCO) is 12% more carbon-

intensive on a “wells to wheels” basis than gasoline. Th at means oil sands suppliers

would need to achieve a 20% total reduction in carbon intensity over the next

decade in order to comply with an LCFS based on the California standard. Options

include increasing the use of electricity, natural gas and low-carbon renewable fuels

in the overall transportation mix.

Off set allowances permitted within the transportation sector could create a market

for LCFS credits that would help oil sands producers comply with these rules. We

estimate that a $100/ton price for such LCFS credits would eff ectively raise the price

of SCO by $11.40 per barrel to meet an LCFS standard with a 10% carbon-intensity

reduction target (equal to a 20% reduction for synthetic crude). However, because

conventional gasoline producers would also be in the market for LCFS credits, and

need proportionately fewer credits to meet LCFS requirements, they would be the

likely drivers of this market. Th is may leave oil sands producers with only the most

expensive LCFS purchase options—or possibly no credits at all.

A related government policy goal is to increase the production of advanced renewable

fuels with low-carbon content, such as cellulosic ethanol, so that it can be blended

with petroleum to meet the LCFS. However, it is possible—perhaps even likely—

that the ambitious targets set forward by the U.S. Congress for 36 billion gallons of

advanced biofuels production per year by 2022 will not be met. In the unlikely event

that no options emerge for Canadian oil sands producers to comply with a federally

adopted LCFS—including no use of blended renewable fuels or other off sets through

trading systems—the U.S. transportation market could conceivably disappear

for Canadian oil sands producers. Th is worst-case scenario would leave oil sands

Low Carbon Fuel Standards

could cut demand for oil

sands production in half.


producers with less U.S. demand in 2030 than the estimated 2 mbbl/d of production

estimated under the Operating and Construction scenario discussed in this report—

possibly eliminating further expansion of oil sands production in the decade ahead.

If the advanced renewable fuel targets are met, however, oil sands producers would

have more justifi cation to expand production. Th is result is somewhat counter-

intuitive: even though more renewable fuels would be available to displace gasoline and

synthetic crude oil in motor fuels, they would also reduce the overall carbon intensity

of blended motor fuels; hence, more carbon-intensive SCO from oil sands could be

added as part of an LCFS-compliant fuel mix. Th is means oil sands producers have a

strong incentive to see the renewable fuels market grow and fl ourish.

Th at said, the adoption of LCFS standards still would have a negative impact on

projected oil sands production under any scenario considered in this report. For

example:

A U.S. federal standard that seeks a 20% reduction in the carbon intensity of

transportation fuels could eliminate 1.2 mbbl/d of oil sands production by

2030—a 33% reduction relative to the CAPP Growth forecast (from 3.7 mbbl/d

down to 2.5 mbbl/d).

If a proposed federal LCFS standard is held at a 10% reduction after 2020, the

estimated reduction in oil sands production would be limited to 0.9 mbbl/d,

with production at 2.8 mbbl/d.

If only certain regions of the United States adopted an LCFS with a 20%

reduction in carbon intensity through 2030, estimates of oil sand production

would vary accordingly. For example, if half of the U.S. motor fuels market

adopted this standard, we project that oil sands production volume would

reach 2.95 mbb/d in 2030. Production would rise to 3.2 mbbl/d if only

California and the Northeast, representing a quarter of the U.S. market,

adopted such an LCFS. In this last instance, production volume would decline

13.5% relative to the CAPP Growth forecast.

Figure RR. Oil Sands Production Comparisons (mbbl/d)

Source: RiskMetrics Group, referencing CAPP production forecasts

4000

3500

3000

2500

2000

1500

1000

500

0

20072008

20092010

20112012

20182026

20282016

20222024

20142020

20132015

20172019

20212023

20252027

20292006

2005

CAPP Growth

Federal LCFS

Lower RF availability

CAPP Ops & Constr


2030

10

00

bb

ls/d

ay


Accordingly, investors must watch carefully as low-carbon and renewable fuel

standards are implemented regionally and possibly federally in the United States

and Canada. One outcome might be that oil sands producers look to other markets

that don’t impose such carbon-intensity limits on motor fuels. Th is in turn raises the

question of whether they would be able to tap these markets. Prospects for such

expansion appear mixed, at best. First, Canada’s oil sands producers must overcome

opposition from many First Nation governments that oppose development of new

pipelines across their territories to port cities on Canada’s west coast. Second, these

producers must consider whether other export markets, principally in Asia, will also

be adopting LCFS rules or other restrictions on carbon emissions in the time frame

that the necessary infrastructure would be built, including refi neries to process the

bitumen. PetroChina’s move to take a 60% stake in Athabasca Oil Sands Corporation’s

in-situ projects in September 2009 indicates that a possible Asian connection is still

in play.102 But it does not mean that the obstacles have diminished.

Accordingly, low carbon fuel standards raise important questions for investors. Th ese

include whether oil sands companies:

factor LCFS as a contingency in their production forecasts

plan to invest in LCFS credits as a compliance option, and estimate the price

and availability of these credits

support investments in advanced renewable fuels, such as cellulosic ethanol,

which provide an optimal blending fuel for synthetic crude oil

are looking beyond possibly LCFS-constrained markets such as the United

States to other export markets, principally in Asia, where such constraints may

emerge more slowly

consider time frame investments in new pipelines, port terminals and refi neries

would take shape, and the risks and obstacles to moving forward with such

plans

While the spread of LCFS standards from California to other regions of the United

States and Canada may be a near-term threat to the oil sands industry, it could work

to the industry’s longer-term advantage by promoting some mutual national policy

objectives. Most existing Canadian oil sands pipelines feed into the U.S. Midwest,

which has substantial infrastructure in place to process this fuel and combine it with

its signifi cant ethanol production capabilities. Building on this relationship with new

investments in advanced renewable fuels would not only help achieve compliance

with LCFS standards, but also spur more employment in clean technology industries

and promote regional energy independence that would enable Canada and the

United States to better compete against European and Asian nations as they advance

their own low-carbon economies.

5.6 Water Use Among the other potential environmental considerations in future oil sands

production, water issues loom large. Th is is especially true for oil sands mining

operations, where up to four barrels of water are consumed for each barrel of synthetic

102. “PetroChina-controlled Athabasca Oil Sands to be listed on Toronto Stock Exchange,” Xinhua News

Agency, Apr. 2, 2010.

Oil sands producers

should actively support

development of advanced

renewable fuels.


crude oil produced. (Th e ratio is below 1:1 for in-situ producers, because they rely

more on recycled water from underground aquifers.) Th e Mackenzie River watershed

in Canada faces the specter of a long-term decline in water supplies. Climate change

is already shrinking glaciers that feed into the Athabasca River, the source of the water

for much of Alberta’s oil sands production. Some studies suggest that by mid-century

regional climate impacts could reduce the Athabasca River’s water fl ow by 50% during

winter months, when the availability of water for industrial use is most restricted.103

Water shortages for oil sands producers could emerge well before the middle of

the century. Water diversions in the Athabasca River and its tributaries are already

restricted during low-fl ow periods—typically from November through mid-April—

in order to protect fi sh habitat. Our analysis indicates that some oil sands mining

producers that are especially dependent on securing freshwater supplies could

encounter wintertime cut-off s as early as 2014 as they try to scale up production. Th is

is likely to spur signifi cant additional investments in water storage, treatment and

recycling facilities.

Accordingly, a key water metric for investors to track is the ratio of barrels of water

consumed for each barrel of oil equivalent produced (boe), especially for oil sands

miners. Th ose with a high water use rate of 4.5:1 could be subject to wintertime

access restrictions by 2014 under both the Growth and Operating & Construction

scenarios outlined in this report. By contrast, oil sands miners with a water

consumption rate of only 2:1 should be able to maintain uninterrupted freshwater

withdrawals under either scenario for the foreseeable future. However, as production

rises, pressure will mount on all oil sands producers to achieve average water

withdrawal ratios below 4:1 by 2020.

Another factor in the water withdrawal equation is that legacy oil sand miners

received far more generous access to the Athabasca River watershed than more

recent entrants. A key development to watch is whether the Albertan government

will successfully renegotiate a more equitable redistribution of water withdrawal

permits. So far, legacy producers have not been willing to give up their claims. At the

same time, legacy producers must be mindful of competing demands by agricultural,

municipal and other industrial users that want more access to this supply. In the

event that climate change makes regional water shortages more acute, pressure will

mount even further on these legacy miners to give up some of their claims to this

precious natural resource.

In addition, oil sands producers face new provincial regulations on the measurement,

use and recycling of water. Th e regulations seek more recycling of water drawn from

underground aquifers, and give preference to use of saline rather than freshwater.

Saline water that is not recycled would have to be treated, adding to total water

management costs. As a result, in-situ producers who rely more on underground

aquifers could face water treatment costs matching those of mining producer who

draw mainly on surface, freshwater supplies—in both cases reaching as high as 5% of

total operating costs.104

103. David Schiller and Vic Adamowicz, “Running Out of Steam? Oil Sands Development and Water Use in the

Athabasca River-Watershed: Science and Market-Based Solutions,” University of Toronto, Munk Centre,

May 2007.


Limited, Jan. 2005.

Oil sands producers will

need to invest more in water

storage, treatment and

recycling.


In summary, the large-volume water requirements by oil sands producers place

a particular need on responsible water management. Seasonal changes in water

availability make it especially important that mining producers invest in water

storage and recycling. In-situ producers—while facing fewer water supply

requirements overall—still need good-quality water for steam generation. Th is results

in higher costs of water treatment from various sources, including from underground

saline aquifers.

Water treatment is tied to ultimate reclamation of tailing ponds, another contentious

issue with high potential costs down the road. Land reclamation issues are

summarized in the next section.

5.7 Land Reclamation Land reclamation and water treatment issues are inextricably linked in Alberta’s oil

sands. Boreal forests in the Athabasca River watershed have been cut down and

fragmented by oil sands production, turning much of the area into an industrial

wasteland. In the process, one of the world’s cleanest environments now poses a

potential threat to public health.

Oil sands mining operations are especially visible on the landscape, as trees are

cleared and topsoil scraped away to expose sands laden with bitumen. Water drawn

from the Athabasca River helps transport this sand to treatment facilities, where the

combination is heated to separate bitumen from the sand. Th e bitumen undergoes

further treatment to become synthetic crude oil. Th e remaining water and toxic

petroleum slurry is deposited in tailings ponds, where it takes decades to separate

the remaining clay from the water in which it was transported and processed.

In-situ operations have less impact on the surface, since they inject steam deeper

underground to bring bitumen to the surface. But they have a much broader

footprint across the boreal forest, with production facilities and pipelines

fragmenting it into many parts. In-situ production also requires large volumes of

natural gas that add to the carbon-intensity of the process. Produced waste liquids

are mainly re-injected underground, but some surface water withdrawals and

wastewater treatment are also required.

As of mid-2009, more than 530 square kilometers of land (equal to 53,000 hectares)

were disturbed by oil sands mining activity in Alberta, an area the size of Delaware.105

Approximately 3.1 million barrels (597,000 tons) of sediment have been spread out in

tailings ponds over 13,000 ha, or one-quarter, of this landscape. Th ese tailings ponds

extend over an area roughly the size of Washington, D.C. Th is toxic mixture of water,

sand, clay, residual bitumen, organic contaminants, salt and trace metals is growing.

Left alone, it will take decades to process these tailings into reusable soil and clean

water.

In 40 years of oil sands production, no tailings ponds have yet been fully reclaimed.

Th at is because, while mature fi ne tailings settle out after three to fi ve years, the

fi ne tailings remain suspended. As a result tailing ponds could substantially alter the

surrounding ecosystem by contaminating soil and water sources, presenting both

health problems to downstream communities and the potential of a catastrophic

105. Government of Alberta, http://www.energy.gov.ab.ca/OilSands/791.asp.

Land reclamation remains

one of the biggest fi nancial

and environmental

challenges facing oil sands

producers.


breach. Th is issue is one of the oil sands industry’s biggest long-term environmental

challenges, especially for legacy oil sands miners like Suncor and Canadian Oil Sands

Trust.

As discussed in Chapter 2, Alberta’s Energy Resources Conservation Board (ERCB) is

tightening oil sands tailings management under Directive 74. Th is directive requires

mined oil sands producers to remediate existing tailings ponds, where disposal has

been completed, within fi ve to eight years, and progressively recycle more tailings

in the future. Because fi ne tailings (FT) take as long as 40 years to settle, and current

technology is not yet able to expedite this process, companies may be forced to use

alternative processes such as bioremediation or Suncor’s proprietary MFT drying and

accelerated dewatering process to meet the schedule set by the ERCB.

Bioremediation as a wastewater treatment option off ers several advantages. By

treating wastewater early in tailings discharge, it reduces sedimentation time and

the need for long-term pond storage. Th is method also helps to solve toxicity

issues and reduces the risk of downstream and underground water contamination.

Bioremediation is still expensive, however, even under the optimistic modeling

assumptions used in this report. If bioremediation were used to treat new tailings

production, our analysis indicates that Imperial Oil could see a 6-17% increase in

its debt-to-capitalization ratio, and Canadian Oil Sands Trust (COST) could see a

10–26% increase, in order to cover the added asset retirement obligations for existing

tailings sands projects.

Taken together, water management and land reclamation are major issues that get

minimal attention on oil sands producers’ balance sheets. Accordingly, investors

should consider the following questions to oil sands producers on this topic:

Do oil sands producers track and report on water use from the Athabasca River

and underlying Mackenzie River watershed?

What strategies do they have in place to reduce water withdrawals from this

watershed?

Will legacy producers with more generous water allowances be forced to give

up a portion of their future supply to new entrants?

Are possible reductions in water supply from climate change being factored

into these decisions?

What current water-to-oil production requirements are needed for specifi c

mining and in-situ projects?

What water reduction targets are being set for the future, including increased

recycling rates for fresh and saline water?

What other cumulative impacts of oil sands production are being measured

and assessed, such as air quality, human health and biodiversity impacts?

With respect to tailings reclamation, how will Directive 74 aff ect operating

costs and asset retirement obligations (ARO) of oil sands operators?

More generally, how will oil sands operators refl ect the costs of water

treatment, land and air reclamation on their balance sheets as part of publicly

disclosed risk management plans?


5.8 Aboriginal Consultation As oil sands producers look to expand their operations in Alberta, they need

to address growing concerns about a lack of clear land use plans and water

management strategies, especially in regard to overlapping Aboriginal territories

whose communities may be aff ected. Under Canada’s Constitution, these Aboriginal

communities have a right to conduct their traditional lifestyles and sustain their

livelihoods through hunting and fi shing. Th e national and provincial governments

of Canada have a duty to consult and accommodate these recognized Aboriginal

governments as new developments are proposed in their territories.

To date, this has not happened to the satisfaction of some Aboriginal leaders. Th ey

have passed joint resolutions calling for a moratorium on new oil sands project

approvals until proper engagement and consultation takes place. Th is includes

Coastal First Nations in British Columbia that announced their opposition to a

proposed pipeline that would link Alberta’s oil sands producers to port terminals on

Canada’s west coast. Th is raises the specter of protracted court battles and possible

annulment of leases that could compromise the oil sands industry’s expansion plans.

For obvious reasons, this is a highly material issue for investors.

At least fi ve Aboriginal territories have brought cases before the provincial and

federal government over failed consultation with their local governments. Although

oil sands producers have no formal role in resolving these disputes, as this requires

nation-to-nation negotiations with the Canadian government, several cases also

name corporations as defendants. Accordingly, oil sands producers may be able to

help their cause by engaging more proactively with Aboriginal communities.

In a recent survey of 11 Canadian oil sands producers, only one-third recognize Aboriginal

treaty rights in their corporate policies.106 None incorporate the principle of Free, Prior

and Informed Consent (FPIC), which is a core principle in the territories’ expectations

of consultation. Th e past track record of companies engaging with Aboriginal

communities is mixed. Some acknowledge discussions but many do not report whether

they have negotiated even basic agreements with any impacted communities. A new

eff ort to bring together First Nations and industry representatives is the focus of an All

Parties Core Agreement.107 Th is provides an opportunity for more meaningful discussion

around core development issues, where previous eff orts have failed.

Oil sands producers’ consultation and engagement around Aboriginal rights issues raises a

key set of questions for investors. Important questions include whether the companies:

disclose any risks posed by current Aboriginal rights litigation

acknowledge any contact with Aboriginal communities or agreements they

have put in place

set policies for consultation and engagement to guide future discussions

have defi ned terms for such engagement, including whether it involves Free,

Prior and Informed Consent

describe resources to be made available for these activities and for educating

employees around Aboriginal rights issues


Ceres, Nov. 2009.

107. See Athabasca Tribal Council, http://ryanjanvier.com/atc/about-atc

Aboriginal communities

may increase opposition

to oil sands development if

their rights are not respected

and their concerns are not

addressed.


5.9 Towards a Strategic Plan Eff ective engagement with Aboriginal communities is vitally important to the future

of Canadian oil sands producers. However, this issue should not be viewed in a

microcosm. Th e same questions apply equally to investor concerns about the costs

of land use reclamation and watershed management, as well as climate change and

carbon mitigation goals. All of these challenges place oil sands expansion in jeopardy.

Th ese ongoing risks also create an opportunity to step back from the gold rush

mentality that characterized much of oil sands development before the oil price

collapse in 2008. Oil sands producers should be refl ecting on the lasting impacts

that their proposed development may have on the land and water of Alberta,

surrounding communities and the global environment through climate change. Th ey

should also be carefully examining how their own prospects may be aff ected by rising

production costs, increased liabilities and changing global energy markets, which may

narrow or even close the window of profi tability for oil sands.

In the end, none of these considerations may change company decisions to invest

further in oil sands development. But they could alter the pace and scale at which

appropriate development takes place, and the willingness of companies to address

these challenges as they invest in new projects. Th ey might also give pause to

companies who fi nd that cost-eff ective solutions to many of these challenges

do not yet exist. By putting together a more comprehensive, long-term strategy

in collaboration with impacted communities—one that is well-articulated to

investors—oil sands producers may gain more confi dence in their ambitious

development plans. Th e alternative leaves vital questions hanging in the balance, and

only raises the stakes of the multi-billion dollar gamble now taking place in Alberta’s

vast oil sands region.

Investors need answers in

this $200 billion bet on oil

sands.


Ore Conversion Table

Cubic Meters bbl Tons

1 6.28 2.6

0.159 1 0.41

0.385 2.42 1

0.68 4.28 1.77

Composition of Feedstock (per boe)

% Tons before processing after processing

Sand 73% 1.25 3.12 4.37

Bitumen 10% 0.18 1.11 1.00

Water 4% 0.07 0.45 0.45

Fines and clay*** 13% 0.23 0.55 0.55

Residual bit 0% 0 0 0.10

Total 100% 1.77 5.23 6


Conversion metrics

Oil

1 boe 0.1589873 m3

1 m3 35.34 ft3

1 boe 5.6 ft3

1 tonne 7.33 bbls

1 bbls 0.13643 tonnes

1 tonne 1.16538 m3

1 bbl 42.00 Usgallons

1 tonne 307.86 US gallons

1 tonne 1,165.47 litres

1 bbls 159.00 litres

Water

1 m3 6.2898 bbl

1 bbl 0.159 m3

1 US gallon 3.8 litres

1 bbl 159 litres

1 m3 1000 litres

1 tonne 1 m3

1 bbl 0.16 tonne

CO2

1 m3 of trees can absorbe 1.83 tonne of CO2

1 litre gasoline emits 2.36 kg

1 gallons gasoline emits 30.3 pounds

1 litre diesel emits 2.73 kg

1 gallon diesel emits 22.5 pounds

Land

1 km2 100 hectars

1 ha 100*100 meters area

1 km2 1000*1000 meters area

Tailings

1 bbl 0.191735801 tonnes

1 bbl 223.4623245 litres

1 bbl 0.223444476 m3

REPORT AUTHORS

YULIA REUTERYulia Reuter heads the global oil and gas team for ESG Analytics of RiskMetrics Group. She

joined Innovest Strategic Value Advisors in 2007 to conduct research on the integrated

oil & gas sector. Previously, Ms. Reuter worked for fi ve years conducting oil & gas equity

research and institutional equity sales in the Canadian investment banking sector. She is a

Chartered Financial Analyst and holds a Bachelor’s Degree in Business Administration from

the Groningen University of Applied Sciences (Netherlands). Ms. Reuter is based in Toronto.

DOUG COGANDoug Cogan is Director of Climate Risk Management at RiskMetrics Group. For 25 years, Mr.

Cogan has advised institutional investors, corporations and government agencies on energy

and environmental topics. His 1992 book, Th e Greenhouse Gambit, was one of the fi rst to

analyze business and investment responses to climate change. He has written many reports

for Ceres and the Investor Network on Climate Risk and helped develop the INCR-adopted

Climate Change Governance Framework. He heads a team using the proprietary Carbon Beta

tool to evaluate companies’ carbon risks and strategic profi t opportunities. He is a graduate of

Williams College.

DANA SASAREANDana Sasarean is a senior analyst with the global oil and gas team for ESG Analytics of

RiskMetrics Group. She joined Innovest Strategic Value Advisors in 2005 to conduct research

on extractive industries, including the integrated oil & gas sector. Ms. Sasarean now focuses

on downstream and oil services sectors. She earned a Master’s Degree in Environmental

Studies from York University (Canada) with concentration in the management tools for

sustainability, ISO 14001 and environmental auditing. She also holds a Bachelor’s Degree in

Finance and Banking from the West University of Timisoara (Romania).

MARIO LÓPEZ-ALCALÁMario López-Alcalá is a senior analyst with the Climate Risk Management team at RiskMetrics

Group. He works in the development and structure of research models and analytics for

climate change-exposed industries. Previously, López-Alcalá conducted research on climate

change for the United Nations Development Programme, Th e World Bank, and the European

Commission. López-Alcalá holds a Masters on Environmental Science and Policy from

Columbia University. He has a Bachelors degree in Economics from Instituto Tecnólogico

Autónomo de México, and holds a Law degree from Universidad Nacional Autónoma de

México.

DINAH KOEHLERMs. Koehler is an ESG consultant. She has 17 years of experience in the public and private

sectors and academia. She has worked with the U.S. Environmental Protection Agency’s Offi ce

of Research and Development, National Center for Environmental Research. She has been a

Senior Research Associate on corporate sustainability at the Conference Board, and continues

to serve there in a consulting role. Ms. Koehler earned her doctorate in Environmental Science

and Risk Management from Harvard’s School of Public Health, received an M.A., Law &

Diplomacy from Th e Fletcher School at Tufts University, and a BA from Wellesley College.

Th is report was written by members of the ESG Analytics team at RiskMetrics Group. Yulia

Reuter served as research project manager. Doug Cogan edited the report and wrote its

summary and conclusions. Ms. Reuter and Dana Sasarean conducted macroeconomic

research and drafted the water, land and Aboriginal rights chapters. Mario López-Alcalá and

consultant Dinah Koehler conducted carbon modeling research and drafted the oil sands

production chapter. Th e report authors wish to thank Andrew Logan, Carol Lee Rawn, Peyton

Fleming and Andrew Gaynor of Ceres who along with Ceres consultant Sonia Hamel provided

valuable insights and editing suggestions. Maggie Powell of Maggie Powell Designs produced

this report for publication. Peter Essick, Aurora Photos, provided the cover photograph.

Ceres is a national coalition of investors, environmental groups and other public interest

organizations working with companies to address sustainability challenges such as global

climate change. Ceres directs the Investor Network on Climate Risk, a group of more than 90

investors from the US and Europe managing nearly $10 trillion in assets. Th is report was made

possible through grants from the Energy Foundation, Tides Foundation, Wallace Global Fund,

Oak Foundation and Kresge Foundation. Th e opinions expressed in this report are those of

the authors and do not necessarily represent the views of the sponsors.

RiskMetrics Group (RMG) is a leading provider of risk management and corporate governance

products and services to the fi nancial community. By bringing transparency, expertise and

access to fi nancial markets, RMG’s ESG Analytics Group off ers investors insight into the

fi nancial impact of sustainability risk factors such as climate change, environmental

protection and human and stakeholder capital.

For more information, please contact:

Andrew Logan

Director, Oil & Gas Industry Program

Ceres, Inc.

+1.617.247.0700 ext. 133

[email protected]

RiskMetrics Group wrote and prepared this report for informational purposes.

Although RiskMetrics exercised due care in compiling the information contained herein,

it makes no warranty, express or implied, as to the accuracy, completeness or usefulness of

the information, nor does it assume, and expressly disclaims, any liability arising out of the use

of this information by any party. Th e views expressed in this report are those of the authors

and do not constitute an endorsement by RiskMetrics Group. Changing circumstances may

cause this information to be obsolete.

Copyright 2010 by Ceres

Copyrighted RiskMetrics Group material used with permission by Ceres

Ceres, Inc.

99 Chauncy Street

Boston, MA 02111

www.ceres.org


One Chase Manhattan Plaza

44th Floor

New York, NY 10015

www.riskmetrics.com

Doug Cogan

Director, Climate Risk Management


+1.301.793.6528

[email protected]

Yulia Reuter

Head of Oil & Gas Research, ESG Analytics


+1.416.364.9000, x3484

[email protected]

Canada’s Oil Sands Shrinking Window of Opportunity

May 2010

Ceres99 Chauncy StreetBoston, MA 02111

T: 617-247-0700F: 617-267-5400

www.ceres.org

©2010 Ceres

A Ceres Report

Authored by RiskMetrics GroupYulia Reuter

Doug Cogan

Dana Sasarean

Mario LÓpez Alcalá

Dinah Koehler

Canada's Oil Sands: Shrinking Window of Opportunity

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